Hydrogen production, storage and recovery

ABSTRACT

A method for operating a kerogen-rich unconventional gas reservoir characterized by there being multiple hydraulically-fractured wells drilled thereinto comprises: recovering a methane-containing gas from a first hydraulically-fractured well drilled into the gas reservoir, steam-methane reforming the recovered methane-containing gas to yield a hydrogen gas and an inorganic carbon-containing gas, injecting at least a portion of the hydrogen gas into a second hydraulically-fractured well drilled into the gas reservoir, and injecting at least a portion of the inorganic carbon-containing gas into a third hydraulically-fractured well drilled into the gas reservoir.

CROSS-REFERENCE TO RELATED APPLICATIONS

This patent application is related to the following patent applications:U.S. patent application Ser. No. 17/665,707, filed on Feb. 7, 2022;PCT/US2022/015486 filed on Feb. 7, 2022; U.S. Provisional PatentApplication No. 63/146,847, filed on Feb. 8, 2021; U.S. ProvisionalPatent Application No. 63/195,151, filed on May 31, 2021; U.S.Provisional Patent Application No. 63/240,961, filed on Sep. 5, 2021;U.S. Provisional Patent Application No. 63/294,139, filed on Dec. 28,2021; and U.S. Provisional Patent Application No. 63/301,503, filed onJan. 21, 2022; all of which are incorporated herein by reference intheir entirety.

FIELD OF THE INVENTION

The present invention relates to methods and systems for production,storage and recovery of a hydrogen-containing gas in a geologicalformation comprising a partially-depleted unconventional gas reservoir,and particularly to methods and systems for recovering the hydrogen gasat a high level of purity.

BACKGROUND

Achieving a diversified low-carbon emissions energy economy has beenlimited by economic and technological limitations. Economic limitationsinclude the cost of renewable energy projects compared to the value ofthe energy production, as well as competition from low-cost fossilfuels. Technological limitations are related to the energy productionefficiency, storage of enormous amounts of excess energy, and ability toconnect energy sources to users.

For example, renewable energy sources like solar and wind haveintermittency challenges in which excess energy is produced withinsufficient storage capacity. Thus, capital costs are increased becausethe solar and wind farms are built for peak power loads which are oftentwice or three times the mean (levelized) power loads. One of the waysto make renewable energy sources more economical is to provide largescale, inexpensive, geographically diversified, and energy efficientstorage solutions. Currently, complex, expensive storage facilities areused to store excess energy (e.g. pumped hydroelectric storage,batteries, thermal storage), and the conversion efficiency is low.

The enormous scale of hydrogen storage that is required to support agreen economy is so large that it necessitates some form of geologicalstorage. This is because geological storage is the only form of storagethat is both large enough and inexpensive enough to be practical at thepresent time. When combined with oxygen, hydrogen can be used in a fuelcell or combustion process to create electricity. However, hydrogenproduction and storage limitations make the transition to a hydrogeneconomy difficult. Therefore, there is a need for low-emissions systemsand methods for large-scale energy-efficient storage and recovery ofhydrogen where the recovered hydrogen is of high purity.

SUMMARY

A method is disclosed, according to embodiments of the invention, foroperating a kerogen-rich unconventional gas reservoir characterized bythere being multiple hydraulically-fractured wells drilled thereinto.The method comprises: recovering a methane-containing gas from a firsthydraulically-fractured well drilled into the gas reservoir;steam-methane reforming the recovered methane-containing gas to yield ahydrogen gas and an inorganic carbon-containing gas; injecting at leasta portion of the hydrogen gas into a second hydraulically-fractured welldrilled into the gas reservoir; and injecting at least a portion of theinorganic carbon-containing gas into a third hydraulically-fracturedwell drilled into the gas reservoir.

A method is disclosed, according to embodiments of the invention, foroperating a kerogen-rich unconventional gas reservoir characterized bythere being multiple hydraulically-fractured wells drilled thereinto.The method comprises: receiving a methane-containing gas; steam-methanereforming the methane-containing gas to yield a hydrogen gas and aninorganic carbon-containing gas; injecting at least a portion of thehydrogen gas into a first hydraulically-fractured well drilled into thegas reservoir; and injecting at least a portion of the inorganiccarbon-containing gas into a second hydraulically-fractured well drilledinto the gas reservoir.

A method is disclosed, according to embodiments of the invention, foroperating a kerogen-rich unconventional gas reservoir characterized bythere being multiple hydraulically-fractured wells drilled thereinto bymultiple hydraulically-fractured wells. The method comprises: (a)receiving a methane-containing gas; (b) steam-methane reforming themethane-containing gas to yield a hydrogen gas and an inorganiccarbon-containing gas; (c) injecting at least a portion of the hydrogengas into a first hydraulically-fractured well drilled into the gasreservoir; (d) injecting at least a portion of the inorganiccarbon-containing gas into a second hydraulically-fractured well drilledinto the gas reservoir; (e) recovering, from the firsthydraulically-fractured well, a hydrogen-containing gas having an H2molar fraction of at least 85%; and (f) generating electricity from atleast a portion of the recovered hydrogen-containing gas.

According to embodiments of the invention, a system for producing,storing and subsequently recovering a hydrogen-containing gas comprises:(a) a steam-methane reformer for receiving and steam-reforming amethane-containing gas to yield a hydrogen gas and an inorganiccarbon-containing gas; (b) pumping arrangements for thehydrogen-containing gas, disposed in fluid communication with a firstpartially-depleted, hydraulically-fractured well drilled into akerogen-rich, unconventional reservoir of the methane-containing gas,and operative to inject the hydrogen gas through a respective horizontalwellbore into the first hydraulically-fractured well at a pressurehigher than a current gas pressure at the wellbore, the partialdepletion of the first hydraulically-fractured well being by amethane-containing-gas recovery process characterized by a maximum flowrate of FLOW_(MAX), and a minimum flow rate of FLOW_(MIN) that is atleast 10% of FLOW_(MAX) and not more than 20% of FLOW_(MAX); (c) pumpingarrangements for the inorganic carbon-containing gas, disposed in fluidcommunication with a second partially-depleted, hydraulically-fracturedwell drilled into the kerogen-rich, unconventional reservoir, andoperative to inject the hydrogen gas through a respective horizontalwellbore into the second hydraulically-fractured well at a pressurehigher than a current gas pressure at the wellbore, the partialdepletion of the second hydraulically-fractured well being by amethane-containing-gas recovery process characterized by a maximum flowrate of FLOW_(MAX), and a minimum flow rate of FLOW_(MIN) that is atleast 10% of FLOW_(MAX) and not more than 30% of FLOW_(MAX); and (d)gas-recovery equipment disposed in fluid communication with the firsthydraulically-fractured well and operative to recover a portion of thehydrogen-containing gas through the respective horizontal wellbore, therecovered portion of the hydrogen-containing gas having an H₂ molarfraction of at least 85%.

A method is disclosed, according to embodiments of the invention, forstoring hydrogen gas in a kerogen-rich geological formation. The methodcomprises: (a) injecting a fracturing fluid through a horizontalwellbore into the geological formation to cause fracturing within thegeological formation; (b) recovering a methane-containing gas throughthe wellbore, the recovering characterized by a maximum flow rateFLOW_(MAX); (c) monitoring a current flow rate FLOW_(CURRENT) of therecovered methane-containing gas over time; (d) responsively to andcontingent upon the monitored FLOW_(CURRENT) being equal to or less thana flow-rate trigger criterion FLOW_(TRIGGER), injecting a hydrogen gasthrough the wellbore into the geological formation at a pressure higherthan a current gas pressure at the wellbore; and (e) recovering, throughthe wellbore, a hydrogen-containing gas having an H₂ molar fraction ofat least 85%, wherein FLOW_(TRIGGER) is equal to at least 10% ofFLOW_(MAX) and not more than 20% of FLOW_(MAX).

A method is disclosed, according to embodiments of the invention, forstoring and subsequently recovering a hydrogen gas. The methodcomprises: (a) injecting the hydrogen gas through a horizontal wellboreinto a hydraulically-fractured, kerogen-rich, and partially-depletedreservoir of a methane-containing gas, at a pressure higher than acurrent gas pressure at the wellbore, the partial depletion of thereservoir being by a methane-containing-gas recovery processcharacterized by a maximum flow rate of FLOW_(MAX), and a minimum flowrate of FLOW_(MIN) that is at least 10% of FLOW_(MAX) and not more than20% of FLOW_(MAX); and (b) recovering a portion of the hydrogen gasthrough the wellbore, the recovered portion of the hydrogen gas havingan H₂ molar fraction of at least 90%.

According to embodiments of the invention, a system for storing andsubsequently recovering a hydrogen-containing gas comprises: (a) pumpingarrangements for hydrogen-containing gas, disposed in fluidcommunication with a hydraulically-fractured, kerogen-rich andpartially-depleted reservoir of a methane-containing gas and operativeto inject the hydrogen gas through a horizontal wellbore into thereservoir at a pressure higher than a current gas pressure at thewellbore, the partial depletion of the reservoir being by amethane-containing-gas recovery process characterized by a maximum flowrate of FLOW_(MAX), and a minimum flow rate of FLOW_(MIN) that is atleast 10% of FLOW_(MAX) and not more than 20% of FLOW_(MAX); and (b)gas-recovery equipment disposed in fluid communication with thereservoir and operative to recover a portion of the hydrogen-containinggas through the wellbore, the recovered portion of thehydrogen-containing gas having an H₂ molar fraction of at least 90%.

A method is disclosed, according to embodiments of the invention, ofstoring and subsequently recovering hydrogen gas in a kerogen-richunconventional gas reservoir. The method comprises: (a) injecting afracturing fluid through a horizontal wellbore into the geologicalformation to cause fracturing within the gas reservoir; (b) recovering amethane-containing gas through the wellbore; (c) monitoring an isotopicsignature respective of at least one molecular component of therecovered methane-containing gas; (d) responsively to and contingentupon reaching an isotopic-signature trigger criterion based upon themonitored isotopic signature, injecting hydrogen gas through thewellbore into the geological formation at a pressure higher than ashut-in gas pressure at a wellhead; and (e) recovering, through thewellbore, a hydrogen-containing gas having an H₂ molar fraction of atleast 85%.

A method is disclosed according to embodiments, of storing andsubsequently recovering hydrogen gas in a kerogen-rich,hydraulically-fractured unconventional gas reservoir. The methodcomprises: (a) sampling, at a plurality of times, a methane-containinggas recovered from the geological formation through a horizontalwellbore; (b) determining, from each sampling, an isotopic signature ofa molecular component in the sampled methane-containing gas, theisotopic signature being based upon an isotope ratio; (c) responsivelyto and contingent upon detecting an increase in the isotopic signatureof at least two successive samplings, injecting hydrogen gas through thewellbore into the geological formation at a pressure higher than ashut-in gas pressure, and (d) recovering, through the wellbore, ahydrogen-containing gas having an H₂ molar fraction of at least 85%.

According to embodiments disclosed herein, a system for storing andsubsequently recovering a hydrogen-containing gas comprises: (a) pumpingarrangements for a hydrogen-containing gas, disposed in fluidcommunication with a hydraulically-fractured, kerogen-rich andpartially-depleted reservoir of a methane-containing gas and operativeto inject the hydrogen gas through a horizontal wellbore into thereservoir at a pressure higher than a current gas pressure wellhead at apressure higher than the shut-in gas pressure at a wellhead, the partialdepletion of the reservoir being by a methane-containing-gas recoveryprocess characterized by an initial isotope signature valueδ(MC)_(INITIAL), a minimum isotopic signature value δ(MC)_(MIN), and acurrent isotopic signature value δ(MC)_(CURRENT) greater thanδ(MC)_(MIN), wherein MC is a molecular component in the sampledmethane-containing gas and δ(MC) is based upon an isotope ratio of themolecular component MC of the methane-containing gas, and (b)gas-recovery equipment disposed in fluid communication with thereservoir and operative to recover a portion of the hydrogen-containinggas through the wellbore, the recovered portion of thehydrogen-containing gas having an H₂ molar fraction of at least 85%.

A method is disclosed according to embodiments, for storing andrecovering hydrogen gas in a kerogen-rich unconventional gas reservoir.The method comprises: (a) injecting a fracturing fluid through ahorizontal wellbore into the gas reservoir to cause fracturing withinthe gas reservoir; (b) recovering a methane-containing gas through thewellbore; and (c) projecting a reservoir isotope ratio valueI-RATIO_(RES)(T_(RES)) respective of one or more molecular components ofa methane-containing gas recovered from the gas reservoir at each of aplurality of corresponding reservoir pressures PRESSURE_(RES)(T_(RES))at respective reservoir times T_(RES), wherein the projecting includes:(i) sampling a gas mixture recovered from a gas-reservoir core sample todetermine a plurality of core-sample value-pairs for respectivecore-sample times T_(CS), each core-sample value-pair including acore-sample isotope ratio I-RATIO_(CS)(T_(CS)) value and a respectivecore-sample pressure value PRESSURE_(CS)(T_(CS)), and (ii) matchingPRESSURE_(RES)(T_(RES)) values with respective PRESSURE_(CS)(T_(CS))values of the plurality of core-sample value-pairs to projectI-RATIO_(RES)(T_(RES)) values based on respective I-RATIO_(CS)(T_(CS))values corresponding to the matched respective PRESSURE_(CS)(T_(CS))values. The method additionally comprises: (d) responsively to andcontingent upon reaching an isotopic-signature trigger criterion basedupon said projecting of reservoir isotope ratio valuesI-RATIO_(RES)(T_(RES)), injecting hydrogen gas through the wellbore intothe geological formation at a shut-in gas pressure at a wellhead; and(e) recovering, through the wellbore, a hydrogen-containing gas havingan H₂ molar fraction of at least 85%.

A method is disclosed, according to embodiments, for storing andrecovering hydrogen gas in a kerogen-rich unconventional gas reservoir.The method comprises: (a) injecting a fracturing fluid through ahorizontal wellbore into the gas reservoir to cause fracturing withinthe gas reservoir; (b) recovering a methane-containing gas through thewellbore; and (c) projecting an H₂ molar fraction χ(H₂)_(RES)(T_(RES))of a hydrogen-containing gas recovered from the gas reservoir at each ofa plurality of corresponding reservoir pressures PRESSURE_(RES)(T_(RES))at respective reservoir times T_(RES), the projecting including: (i)sampling a hydrogen-containing gas recovered from a gas-reservoir coresample held in the core-sample holder, to determine a plurality ofcore-sample value-pairs for respective core-sample times T_(CS), eachcore-sample value-pair including an H₂ molar fraction valueχ(H₂)_(CS)(T_(CS)) and a respective core-sample pressure valuePRESSURE_(CS)(T_(CS)), and (ii) matching PRESSURE_(RES)(T_(RES)) valueswith respective PRESSURE_(CS)(T_(CS)) values of the plurality ofcore-sample value-pairs to project χ(H₂)_(RES)(T_(RES)) values based onrespective χ(H₂)_(CS)(T_(CS)) values corresponding to the matchedrespective PRESSURE_(CS)(T_(CS)) values. The method additionallycomprises: (d) responsively to and contingent upon reaching ahydrogen-purity trigger criterion based upon said projecting of H₂ molarfraction values χ(H₂)_(RES)(T_(RES)), injecting hydrogen gas through thewellbore into the gas reservoir at a shut-in gas pressure at a wellhead;and (e) recovering, through the wellbore, a hydrogen-containing gashaving an H₂ molar fraction equal to or greater than the hydrogen-puritytrigger criterion.

A method is disclosed, according to embodiments, for projecting anisotope ratio I-RATIO_(RES) respective of one or more molecularcomponents in a methane-containing gas recovered from a kerogen-richunconventional gas reservoir. The method comprises: (a) receiving, in acore-sample holder, a core sample acquired from the gas reservoir; (b)introducing, into the core-sample holder, a methane-containing gas forwhich an isotope ratio I-RATIO is known, the introducing includingregulating an internal gas pressure of the core-sample holder to aninitial core-sample pressure PRESSURE_(CS-INIT); (c) sampling,periodically, a gas mixture comprising a methane-containing gas producedby a core sample held in the core-sample holder at a core-samplepressure PRESSURE_(CS)(T_(CS)) at respective core-sample times T_(CS);(d) determining a core-sample isotope ratio I-RATIO_(CS)(T_(CS)) of thesampled gas mixture for each of a plurality of samplings; and (e)projecting a reservoir isotope ratio I-RATIO_(RES)(T_(RES)) value for amethane-containing gas recovered from the gas reservoir at acorresponding reservoir pressure PRESSURE_(RES)(T_(RES)) at respectivereservoir times T_(RES), by using a recorded plurality of core-samplevalue pairs each including a I-RATIO_(CS)(T_(CS)) value and acorresponding PRESSURE_(CS)(T_(CS)) value.

A method is disclosed, according to embodiments, for projecting an H₂molar fraction χ(H₂)_(R) of a hydrogen-containing gas recovered fromstorage in a kerogen-rich unconventional gas reservoir. The methodcomprises: (a) receiving, in a core-sample holder, a core sampleacquired from the gas reservoir; (b) sampling, periodically, a gasmixture comprising a hydrogen-containing gas produced by the core samplein the core-sample holder at a core-sample pressurePRESSURE_(CS)(T_(CS)); (c) determining a core-sample H₂ molar fractionχ(H₂)_(CS)(T_(CS)) of the sampled gas mixture for each of a plurality ofsamplings; and (d) projecting a reservoir isotope ratioχ(H₂)_(RES)(T_(RES)) value for a hydrogen-containing gas recovered fromthe reservoir at a corresponding reservoir pressurePRESSURE_(RES)(T_(RES)), by using a recorded plurality of core-samplevalue pairs each including a χ(H₂)_(CS)(T_(CS)) value and acorresponding PRESSURE_(CS)(T_(CS)) value.

According to embodiments of the invention, an apparatus comprises: (a) acore-sample holder for receiving a core sample acquired from akerogen-rich unconventional gas reservoir; (b) pressure-regulatingarrangements arranged to be placed in fluid communication with thecore-sample holder and to evacuate the core-sample holder; and (c) atleast one of: (i) a pressurized volume of a methane-containing gas forwhich an isotope ratio I-RATIO respective of one or more molecularcomponents of the methane-containing gas is known, arranged to be placedin fluid communication with the evacuated core-sample holder andeffective to achieve a gas pressure therein equal to the initialreservoir pressure PRESSURE_(RES-INIT), and (ii) pressurized volume of ahydrogen-containing gas for which an H₂ molar fraction χ(H₂) is known,arranged to be placed in fluid communication with the evacuatedcore-sample holder and effective to achieve a gas pressure therein equalto the initial reservoir pressure PRESSURE_(R-INIT). The apparatusadditionally comprises: (d) a pressure-control valve configured to allowpassage therethrough of a gas mixture which comprises amethane-containing gas produced by the core sample, at a core-samplepressure PRESSURE_(CS)(T_(CS)) at respective core-sample times T_(CS);(e) one or more gas-sampling containers arranged to receive the gasmixture passed through the pressure-control valve; and (f)instrumentation for measuring the core-sample pressurePRESSURE_(CS)(T_(CS)) and a core-sample isotope ratioI-RATIO_(CS)(T_(CS)) of the gas mixture at respective core-sample timesT_(CS).

BRIEF DESCRIPTION OF THE DRAWINGS

The invention will now be described further, by way of example, withreference to the accompanying drawings, in which the dimensions ofcomponents and features shown in the figures are chosen for convenienceand clarity of presentation and not necessarily to scale. In thedrawings:

FIG. 1 is a schematic illustration showing multiple wellpads, andmultiple wells drilled into a gas reservoir.

FIG. 2A is a schematic diagram of a system for producing, storing andsubsequently recovering a hydrogen-containing gas comprising asteam-methane reformer, pumping arrangements for the hydrogen-containinggas and for an inorganic carbon-containing gas, gas-recovery equipment,gas transportation arrangements, and electricity generation andtransmission arrangements, according to embodiments of the presentinvention.

FIG. 2B is a schematic detail of a system producing, storing andsubsequently recovering a hydrogen-containing gas comprising asteam-methane reformer, showing an SMR furnace, according to embodimentsof the present invention.

FIG. 2C is a schematic detail of a system producing, storing andsubsequently recovering a hydrogen-containing gas comprising asteam-methane reformer, showing a blending facility, according toembodiments of the present invention.

FIG. 3 is a schematic illustration showing recovery of amethane-containing gas from a geological formation through a horizontalwellbore, according to embodiments of the present invention.

FIG. 4 shows a graph schematically showing the relationship between aminimum flow rate and a maximum flow rate in a gas-recovery process,according to embodiments of the present invention.

FIG. 5 is a schematic illustration showing injection of hydrogen gasthrough a horizontal wellbore into a geological formation, according toembodiments of the present invention.

FIG. 6 is a schematic illustration showing recovery of ahydrogen-containing gas from a geological formation through a horizontalwellbore, according to embodiments of the present invention.

FIGS. 7-11 show flowcharts of methods and method steps for operating akerogen-rich unconventional gas reservoir, according to embodiments ofthe present invention.

FIG. 12 is a schematic diagram of a system for producing, storing andsubsequently recovering a hydrogen-containing gas comprising asteam-methane reformer, pumping arrangements for the hydrogen-containinggas and for an inorganic carbon-containing gas, gas-recovery equipment,gas transportation arrangements, and electricity generation andtransmission arrangements, according to embodiments of the presentinvention.

FIGS. 13-20 show flowcharts of methods and method steps for operating akerogen-rich unconventional gas reservoir, according to embodiments ofthe present invention.

FIG. 21 shows a timeline of activities related to a gas reservoir,according to embodiments of the present invention.

FIG. 22 is a flowchart showing steps of a method for storing hydrogengas in a kerogen-rich geological formation, according to embodiments ofthe present invention.

FIG. 23 is a schematic illustration showing injection of a fracturingfluid through a horizontal wellbore into a geological formation,according to embodiments of the present invention.

FIG. 24 is a schematic illustration showing multiple wells and multiplewellpads servicing a gas reservoir, according to embodiments of thepresent invention.

FIG. 25 is a schematic illustration showing recovery of amethane-containing gas from a geological formation through a horizontalwellbore, according to embodiments of the present invention.

FIG. 26 is a graph schematically showing various gas flow-rate declineor decay curves.

FIG. 27A is a schematic cross-sectional illustration of akerogen-containing meso-micropore in a kerogen-containing matrix.

FIG. 27B is a schematic cross-sectional illustration of a nanopore in akerogen-containing matrix.

FIG. 28 is a graph schematically showing the relationship between aflow-rate trigger criterion and a variety of exponential flow-rate decaycurves, according to embodiments of the present invention.

FIG. 29 is a schematic illustration showing injection of hydrogen gasthrough a horizontal wellbore into a geological formation, according toembodiments of the present invention.

FIG. 30 is a schematic illustration showing recovery of ahydrogen-containing gas from a geological formation through a horizontalwellbore, according to embodiments of the present invention.

FIG. 31 is a graph schematically illustrating various phases of gasrecovery and storage, according to embodiments of the present invention.

FIG. 32 is a graph schematically showing the relationship between aminimum flow rate and a maximum flow rate in a gas-recovery process,according to embodiments of the present invention.

FIGS. 33, 34 and 35 are flowcharts showing steps of respective methodsfor storing and subsequently recovering a hydrogen gas, according toembodiments of the present invention.

FIG. 36 shows a timeline of activities related to a gas reservoir,according to embodiments of the present invention.

FIG. 37 is a flowchart showing steps of a method for storing hydrogengas in a kerogen-rich geological formation, according to embodiments ofthe present invention.

FIG. 38 is a schematic illustration showing injection of a fracturingfluid through a horizontal wellbore into a geological formation,according to embodiments of the present invention.

FIG. 39 is a schematic illustration showing multiple wells and multiplewell pads servicing a gas reservoir, according to embodiments of thepresent invention.

FIG. 40 is a schematic illustration showing recovery of amethane-containing gas from a geological formation through a horizontalwellbore, according to embodiments of the present invention.

FIG. 41 is a chart showing an exemplary graph of a δ(¹³C) isotopicsignature over time, according to embodiments of the present invention.

FIG. 42 is a chart showing an exemplary graph of a deuteratedhydrocarbon isotope ratio over time, according to embodiments of thepresent invention.

FIG. 43 is a schematic illustration showing injection of hydrogen gasthrough a horizontal wellbore into a geological formation, according toembodiments of the present invention.

FIG. 44 is a schematic illustration showing recovery of ahydrogen-containing gas from a geological formation through a horizontalwellbore, according to embodiments of the present invention.

FIG. 45 shows a flowchart of method steps for storing and subsequentlyrecovering a hydrogen-containing gas, according to embodiments of thepresent invention.

FIG. 46 shows a timeline of activities related to a gas reservoir,according to embodiments of the present invention.

FIGS. 47A, 47B and 47C are flowcharts showing method steps for storingand recovering hydrogen gas in a kerogen-rich geological formation,according to embodiments of the present invention.

FIG. 48 is a schematic illustration showing injection of a fracturingfluid through a horizontal wellbore into a geological formation,according to embodiments of the present invention.

FIG. 49 is a schematic illustration showing multiple wells and multiplewellpads servicing a gas reservoir, according to embodiments of thepresent invention.

FIG. 50 is a schematic illustration showing recovery of amethane-containing gas from a geological formation through a horizontalwellbore, according to embodiments of the present invention.

FIGS. 51A and 51B show a block diagram of a system for measuring isotoperatios, according to embodiments of the present invention.

FIG. 52 is a chart showing an exemplary graph of a δ(¹³C) isotopicsignature over time of a core sample from an unconventional gasreservoir, according to embodiments of the present invention.

FIGS. 53 and 54 are charts showing exemplary graphs of a gas pressureover time, of a core sample from an unconventional gas reservoir and ofthe gas reservoir, respectively, according to embodiments of the presentinvention.

FIG. 55 is a chart showing an exemplary graphs of a projected δ(¹³C)isotopic signature of the gas reservoir over time, according toembodiments of the present invention.

FIG. 56 is a schematic illustration showing injection of hydrogen gasthrough a horizontal wellbore into a geological formation, according toembodiments of the present invention.

FIG. 57 is a schematic illustration showing recovery of ahydrogen-containing gas from a geological formation through a horizontalwellbore, according to embodiments of the present invention.

FIGS. 58A and 58B are flowcharts showing method steps for storing andrecovering hydrogen gas in a kerogen-rich geological formation,according to embodiments of the present invention.

FIG. 59 is a chart showing an exemplary graphs of H₂ purity over time,of a core sample from an unconventional gas reservoir, according toembodiments of the present invention.

FIGS. 60 and 61 are charts showing exemplary graphs of a gas pressureover time, of a core sample from an unconventional gas reservoir and ofthe gas reservoir, respectively, according to embodiments of the presentinvention.

FIG. 62 shows a flowchart of method steps for projecting an isotoperatio respective of one or more molecular components in amethane-containing gas recovered from a kerogen-rich unconventional gasreservoir, according to embodiments of the present invention.

FIG. 63 shows a flowchart of method steps for projecting an H₂ molarfraction of a hydrogen-containing gas recovered from storage in akerogen-rich unconventional gas reservoir.

DETAILED DESCRIPTION OF THE ILLUSTRATED EMBODIMENTS

The invention is herein described, by way of example only, withreference to the accompanying drawings. With specific reference now tothe drawings in detail, it is stressed that the particulars shown are byway of example and for purposes of illustrative discussion of thepreferred embodiments of the present invention only and are presented inthe cause of providing what is believed to be the most useful andreadily understood description of the principles and conceptual aspectsof the invention. In this regard, no attempt is made to show structuraldetails of the invention in more detail than is necessary for afundamental understanding of the invention, the description taken withthe drawings making apparent to those skilled in the art how the severalforms of the invention may be embodied in practice. Throughout thedrawings, like-referenced characters are generally used to designatelike elements.

Embodiments disclosed herein relate to systems and methods for storageand recovery of hydrogen gas in geological formations. The term‘hydrogen gas’ as used herein means a hydrogen-containing gas, i.e., agas that includes hydrogen but that may also include other gases. Forexample, ‘hydrogen gas’ or the equivalent ‘hydrogen-containing gas’ canmean a gas mixture having an H₂ molar fraction of less than 100%, whilethe remaining percentage, i.e., 100% less the H₂ molar fraction, iscomposed of molecules of other gases, such as, for purposes ofillustration, methane, ethane, propane, butane, and/or otherhydrocarbons. The term ‘hydrogen’ if used herein means a ‘hydrogen gas’unless otherwise specified, and the two terms may be usedinterchangeably in the present disclosure. The terms ‘natural gas’ and‘methane-containing gas’ are used interchangeably to mean a gas mixtureconsisting primarily of methane. In a non-limiting example, natural gascomprises between 85% and 95% methane.

An unconventional gas reservoir is a reservoir of a methane-containinggas that is not necessarily recoverable by conventional means, butrather is at least partly recoverable by what until recent decades wasconsidered unconventional means—for example, by using hydraulicfracturing, which includes the pressurized injection of a fracturingfluid into a geological formation, to facilitate the release of thenatural gas for recovery. The terms ‘hydraulic fracturing’, and‘fracturing’ are used interchangeably in the present disclosure. A‘well,’ as the term is used herein, is drilled into the geologicalformation, or equivalently, into the unconventional gas reservoir, forrecovery of natural resources, including natural gas. The term‘wellbore’ as used herein is the actual hole that forms the well, and/ormay refer to a pipe that forms a conduit for conveyance of fluids intoand out of the well. Each well comprises a wellhead and a wellbore. Awellbore, including perforated casing, is horizontally-oriented at thedepth of the geological formation, i.e., the shale formation, and canextend horizontally for tens, hundreds or thousands of meters. Duringhydraulic fracturing, a hydraulic-fracturing fluid is injected into (andthrough) the wellbore and thence into fractures. The injecting iseffective to increase pressure at the target depth of the unconventionalgas reservoir, e.g., based on the depth of the wellbore, to exceed thatof the fracture gradient of the rock. At a fracture-initiating pressureknown as a ‘breakdown pressure’, the deep rock surrounding the wellborecracks with pressure. Once fracturing is initiated, pressure at thewellhead drops and then starts increasing, as the fracturing fluid 3permeates the rock, further extending the fractures. This occurs at thefracture-extending pressure FRAC_(EXT). Fractures predominantlyperpendicular to the wellbore may reach lengths of a few hundred feetlong; the height of the fractures is controlled by the stresses in therock formations above and below the wellbore.

According to embodiments of the invention, an unconventional gasreservoir can be suitable for long-term and/or short-term storage ofhydrogen gas after partial depletion of the natural gas. A singlegeological formation or a single unconventional gas reservoir 35 canhave large numbers of multiple hydraulically-fractured wells drilledthereinto, as shown in FIG. 1 . FIG. 1 illustrates multiple wells(indicated by respective wellbores 10) at each wellpad 19, and multiplewellpads 19 servicing the gas reservoir 35. In the non-limiting exampleof FIG. 1 , gas flows through a network of transmission nodes to acentral treatment hub that services the multiple wells. The example ofFIG. 1 shows 8 wells, i.e., wellbores 10, operating from each wellpad19.

In other examples, not illustrated, there can be any number of wells,such as for example, 16, 32 or 64 wells. Similarly, there can be manywellpads servicing a single unconventional gas reservoir. As will bediscussed below, specialized equipment, e.g., for recovery of gases fromthe well or for injection of fluids into the well, can be placed influid communication with specific wells. Pressure and flow measurementsmay be made using pressure and flow gauges at the wellhead while flowingor during shut-in. Pressure may also be measured downhole using downholepressure gauges.

Each of the wells drilled into an unconventional gas reservoir servesfirst for recovery of natural gas from the reservoir. Nonetheless, if awell is drilled that produces gas poorly or is unsuitable for gasrecovery, it might still be purposed for storage of other gases. The gaswells are fractured, and in many cases hydraulically fractured, toproduce natural gas found within the organic material, such as kerogen,that can be present in a concentration of at least 1% or 2% or 3% in anunconventional gas reservoir exploited for natural gas recovery inaccordance with any of the embodiments disclosed herein. For thepurposes of the present disclosure, the term ‘kerogen-rich’ refers to akerogen concentration of at least 1% organic content by volume, or atleast 2%, or at least 3%, or at least 4%, or at least 5%. Kerogenconcentration may be determined on cuttings or core material using thearea under the S2 peak of a Rock-Eval analysis, or, in well logging,from the difference between the neutron and density porosities afteraccounting for the kerogen density and hydrogen index (HI) of clays orusing a pulsed-neutron spectroscopy logging tool. Another method ofmeasuring kerogen includes high frequency (e.g., 20 MHz) nuclearmagnetic resonance (NMR) applied to core material. Kerogen concentrationmay also be determined from an equation based on total organic carbon(TOC). The adsorption on kerogen may be determined by integration ofpetrophysical analysis from lab and well logging data with N₂, CH₄, andH₂ adsorption isotherms. Recovered natural gas can include any or allof: (i) methane residing in fractures or inorganic pore spaces or porespaces in the kerogen within the geological formation; (ii) methaneadsorbed to kerogen surfaces; and (iii) methane dissolved in kerogen.

Some wells, once they are at least partly depleted of recoverablenatural gas, can be repurposed and used for storage of other gases. In afirst example, a hydrogen gas, or a hydrogen-containing gas, can beinjected into a partially depleted well for storage and later recovery,e.g., to capture the economic value of the hydrogen via eventual use inenergy conversion devices such as fuel cells, gas turbines and/orinternal combustion engines installed in vehicles and electric powergeneration facilities. In a second example, an inorganiccarbon-containing gas such as, for example carbon dioxide (CO2) orcarbon monoxide (CO) can be injected into a partially depleted well forstorage, e.g., to prevent the inorganic carbon-containing gas from beingreleased into the atmosphere. Thus, the system disclosed here isconfigured to recover a valuable hydrocarbon—natural gas—and convert itto a non-polluting fuel while storing most of the greenhouse gas contentin geological formations whose economic value has been largely exhaustedby the prior recovery of the natural gas.

Storage of gases in the partially depleted wells can be long-term orshort-term. For example, it can be that in a first partially depletedwell drilled into a particular unconventional gas reservoir, hydrogen isstored for periods of days, hours, weeks, months or even years beforebeing recovered for its economic value. In the same example, it can bethat carbon dioxide is stored in a second partially depleted welldrilled into the same unconventional gas reservoir, with no plan inplace for ever recovering the carbon dioxide gas. Still yet in the sameexample, it can be that at least one other partially depleted well,i.e., a third well drilled into the same unconventional gas reservoir,is still being used in parallel to the storage and/or recovery of thehydrogen and carbon dioxide gases, for economic recovery of the naturalgas produced from the well. Steps can be taken, as will be describedhereinbelow, to ensure that hydraulic fractures in the respective wellsdo not intersect, i.e., communicate fluids to hydraulic fractures inother wells.

Hydrogen can be produced from natural gas in any one of a number ofprocesses and the scope of the present invention does not limit themethods and equipment used for reforming methane to yield hydrogen. Apreferred process is steam-methane reforming, in which steam at700°−1000° C. is used to produce hydrogen (H₂) from methane (CH₄). Anexemplary steam-methane reformer comprises multi-tubular packed-bedreactors, a type of plug flow reactor that includes an array of long,narrow tubes situated within the combustion chamber of a largeindustrial furnace, providing the necessary energy to keep the reactorat a constant temperature during operation. Furnace designs can betop-fired, bottom-fired, or side-fired. Inside the tubes, a mixture ofsteam and methane is put into contact with a high surface-area-to-volumenickel catalyst. Hydrogen gas and carbon monoxide (and a small amount ofcarbon dioxide) are produced in this process. In the water-gas shiftreaction, more hydrogen and carbon dioxide are produced by combiningsteam and the carbon monoxide from the first process. The non-hydrogencomponents are then removed using pressure-swing adsorption. Thesteam-methane reforming reaction is CH₄+H₂O→CO+3H₂, and the water-gasshift reaction is CO+H₂O→CO₂+H₂.

The steam reforming process can receive methane that is recovered onsitefrom one or more wells drilled into the unconventional gas reservoir.Additionally, or alternatively, the process can receive methane that istransported to the site, e.g., via a pipeline or tanker truck, railcaror ship (e.g., as compressed or liquified gas).

Referring now to FIGS. 2A, 2B and 2C, a system 100 for producing,storing and subsequently recovering a hydrogen-containing gas includes asteam-methane reformer (SMR) 42. In the embodiment illustrated in FIG.2A, the SMR 42 is located onsite, i.e., at or in proximity to akerogen-rich unconventional gas reservoir 35. ‘In proximity’ can meanwithin 10 km, or within 50 km, or within 100 km, or within 250 km, orwithin 500 km of the gas reservoir.

The unconventional gas reservoir 35 is characterized by having multiplewells 11 drilled thereinto; in the example of FIG. 2 , the multiplewells 11 include hydraulically-fractured wells 11 ₁, 11 ₂, 11 ₃, 11 ₄,drilled into the reservoir 35. A single one or more wells 11, drilled inreservoir 35. The skilled artisan will understand that these four wellsare illustrative in nature and in practicing the embodiments it islikely to employ an unconventional gas reservoir having many more wellsdrilled into it. In some embodiments, a single SMR 42 serves some, many,most, or all the gas-producing wells 11 drilled into a reservoir 35.

The hydraulic and natural fractures in the respective wells areindicated by the arrows 32, where the direction of the arrows indicatedwhether a gas is being injected into the wells (as in wells 11 ₂ and 11₃) or recovered from the wells (as in wells 11 ₁ and 11 ₄). In theexample of FIG. 2 , wells 11 ₁ and 11 ₄ are being used for natural gasrecovery, and respective gas recovery equipment 80 is in fluidcommunication with the respective wellbores of the two wells 11 ₁ and 11₄. Well 11 ₂ is a partially depleted well, i.e., partially depleted ofnatural gas, and is being used for injecting a hydrogen-containing gasthereinto for storage and later recovery. Hydrogen-gas-pumpingarrangements 90 and hydrogen-gas-recovery equipment 80 are both providedin fluid communication with the reservoir 35 via the wellbore of well 11₂, respectively for injection of hydrogen into the well and for laterrecovery of the stored hydrogen. The pumping arrangements 80 includepumps and compressors, piping, power equipment, and other equipment asnecessary for injecting the hydrogen gas into the well. The pumpingarrangements 80 are configured to inject the hydrogen at a pressurehigher than a current shut-in gas pressure at the wellbore of well 11 ₂.Well 11 ₃ is a partially depleted well being used for injecting aninorganic carbon-containing gas, e.g., CO₂ and/or CO, into the well forstorage. The CO₂ and CO, which are products of the steam-reformingprocess, can be stored in the partially depleted gas wells indefinitely.CO/CO₂-gas-pumping arrangements 91 are provided in fluid communicationwith the reservoir 35 via the wellbore of well 11 ₃, for injection ofthe inorganic carbon-containing gas into the well. CO₂ is preferentiallyadsorbed onto kerogen, displacing residual methane.

The SMR 42 receives a methane-containing gas recovered from thereservoir 35, e.g., via piping the gas recovered from wells 11 ₁ and 11₄, as indicated in FIG. 2 by the arrows marked 911 and 905,respectively. In some embodiments, a portion of the recoveredmethane-containing gas is diverted, as indicated by arrow 907, forshipping offsite by pipeline 72. The main products of the steamreforming process, H₂ and CO/CO₂, are delivered to respective pumpingarrangements 90 and 91, by piping the gases from the SMR 42, asindicated in FIG. 2 by 901 and 910, respectively. In someimplementations, a majority, or even all, of the hydrogen gas producedby the SMR 42 is piped (as indicated by arrow 902, for purposes otherthan storage in the well 11 ₂. The system 100 can include a separator 60for separating H₂ from other gases, especially CH₄. Non-limitingexamples of suitable separators include an embedded membrane in acatalyst tube or a shell-and-tube configuration.

In a non-limiting example, some, or a majority, or even all, of theproduced hydrogen gas is used to generate electricity onsite, forexample by being piped, as indicated by arrow 903, to a gas turbine 45or to a fuel cell 46. In another non-limiting example, some, or amajority, or even all, of the produced hydrogen gas, is sent offsite viaa pipeline 71. As shown in FIG. 2 , a hydrogen-containing gas recoveredfrom well 11 ₂ following storage therein is sent to the separator 60, asindicated by arrow 900, for separation of the H₂ from the CH₄, and/or issent, as indicated by arrow 903, to a gas turbine 45 for generatingelectricity, either with or without separation of the methane at theseparator 60. Hydrogen-containing gas exiting the separator 60, asindicated by arrow 904, yields H₂ which can be used to generateelectricity, for example in the fuel cell 46 (or in the gas turbine 45),or can be shipped offsite by pipeline 71. CH₄ separated from the H₂ atthe separator 60 can be shipped offsite by pipeline 72 or can be sent tothe SMR 42. Electricity generated onsite is delivered offsite byelectricity transmission arrangements 48. In some embodiments, some ofthe generated electricity can be used for compressing gases andinjecting the compressed gases into the unconventional reservoir.

FIG. 2B shows a detail of an exemplary system 100 similar to that ofFIG. 2A, in which gases, e.g., H₂ and/or CH₄, are combusted to createthe heat necessary for the steam-methane reforming process. Twonon-limiting examples of incoming gas flows to combustion facilities 43,44 are shown: H₂+CH₄ from H₂-storage wells such as H₂-storage well 11 ₂of FIG. 2A, indicated again in FIG. 2B by arrow 900, and CH₄ fromCH₄-production wells such as CH₄-production wells 11 ₁ and 11 ₄ of FIG.2A, indicated again in FIG. 2B by arrow 911. These gas flows can firstbe routed to a separator 60. For example, if the combustion processrequires only hydrogen, then the H₂/CH₄ flow 900 is routed first to aseparator facility 60 and thence to the combustion facilities 43, 44.Other gas flows can be exploited for combustion or other purposes; asanother non-limiting example, a portion of the H₂ yielded by the SMRfacility 42 can be returned to the combustion facilities 43, 44 Of theSMR facility 42 and used for combustion.

In the example of FIG. 2B, a boiler 43 generates steam for mixing withthe methane in the SMR process. Burners 44, e.g., top-fired,bottom-fired, and/or side-fired burners, superheat the catalyst-filledreaction tubes of packed-bed reactors.

FIG. 2C shows a detail of another exemplary system 100 similar to thatof FIG. 2A, in which the system 100 includes a blending facility 49.According to embodiments, the blending facility 49 is configured toproduce a blended stream comprising a fixed ratio between two or moregases, e.g., methane and hydrogen at a fixed ratio. FIG. 2C shows twonon-limiting examples of incoming gas flows to the blending facility 49:H₂+CH₄ from H₂-storage wells such as H₂-storage well 11 ₂ of FIG. 2A,indicated again in FIG. 2C by arrow 900, and CH₄ from CH₄-productionwells such as CH₄-production wells 11 ₁ and 11 ₄ of FIG. 2A, indicatedagain in FIG. 2C by arrow 911. As shown, for purposes delivering ablended gas, the blending facility 49 can be arranged in fluidcommunication with an electrical generator such as a gas turbine 45, ora pipeline 75 for off-site transport of the blended gas.

The blending facility 49 can also be arranged to deliver apre-determined mix to a gas-fueled compressor 93. In any of thedisclosed embodiments of system 100, a methane-containing gas and/or ahydrogen-containing gas, either separately or in a mixture, can be used,e.g., combusted, directly in a gas-powered compressor 93 for compressinggases and injecting the compressed gases into the unconventionalreservoir 35.

In another example shown in FIG. 2A, the gas flows of FIG. 2B can firstbe routed to a blending facility 49 in order to achieve a desired mix ofcombustion-fuel gases, indicated in FIG. 2C by arrow 922. for deliveryto the boiler 43 and/or burners 44 of the SMR facility 42. Examples ofsuitable mixtures of combustion-fuel gases include a mix that comprisesat least 15% H₂, or at least 50% H₂, or at least 85% H₂, or at least 90%H₂, or at least 95% H₂, or at least 98% H₂ (all by molar fraction).

Any or all the foregoing functions and features of the described systemscan be combined in any manner in a single embodiment, and not everyembodiment includes every function or feature discussed.

FIG. 3 illustrates recovery of a methane-containing gas 5 through awellbore 10 of a well 11, for example well 11 ₁ of FIG. 2 , drilled intothe unconventional gas reservoir 35 developed in geological formation30. As indicated by directional arrow 202, natural gas 5 is recoveredthrough the wellbore 10 from the reservoir 35, including from thehydraulic fractures 32, and processed by gas recovery equipment 80 whichis in fluid communication with the wellbore 10 at the wellhead 18.

In a well servicing an unconventional gas reservoir, natural gas isrecovered at a flow rate that reaches, within a relatively short time,e.g., one month or less of post-hydraulic fracturing clean-up, a maximumflow rate FLOW_(MAX), and the flow rate thereafter declines. The outputprocess of gas flow can be described by a combination of mechanismsacting at different scales. In an initial period of gas recovery, theflow rate reaches maximum flow rate FLOW_(MAX) and proceeds through theperiod of ‘short-term decline’. The first mechanism is a flow of free(non-adsorbed and non-dissolved) gas molecules from pores and cracks inthe shale formation. After equilibrium is disturbed, for example, by thehydraulic fracturing, the free gas molecules start flowing toward lowerpressure, and are recovered through the wellbore. This flow is calledviscous flow, or ‘Darcy flow’, because the flow through the porousmedium follows Darcy's Law which states that flow of a gas through aporous medium has a linear relationship with both permeability andpressure differential, or, for a given permeability, flow isproportional to pressure differential. Additional gas flow (andrecovery) during the ‘short-term decline’ period occurs by desorption ofmethane from kerogen and clay surfaces, and subsequent flow of the gasmolecules under a pressure gradient. A longer, residual period of‘long-term decline’ is characterized by gas recovered substantially bydiffusion, e.g., Knudsen diffusion, and slip flow in smaller pores,e.g., nanopores.

The recovery process of a reservoir or a particular well can becharacterized, as illustrated schematically in FIG. 4 , by a stretchedexponential, or in some embodiments, hyperbolic, decline in gas recoveryrate from a peak flow rate of FLOW_(MAX) to a minimum flow rate ofFLOW_(MIN). In an example, the value of FLOW_(MIN) of any given well canbe selected based on the economic viability of maintaining the well asactive beyond the minimum flow of FLOW_(MIN), including operating thegas-recovery equipment associated with the well. In another example,wherein the well is associated with an SMR, the value of FLOW_(MIN) canbe selected to take into account the value, e.g., opportunity cost, ofusing the well for storage (and recovery) of the hydrogen gas producedby the SMR or for storage of the inorganic carbon-containing gas (COand/or CO₂) produced by the SMR. FIG. 4 indicates a range of FLOW_(MIN)between 10% and 20% of FLOW_(MAX). These are exemplary values, and inother examples FLOW_(MIN) can be selected to be less than 10% or morethan 20% of FLOW_(MAX).

We now refer to FIGS. 5 and 6 .

FIG. 5 illustrates the injection of hydrogen gas 8 into a well 11, forexample, well 11 ₂ of FIG. 2 . The injection of the hydrogen 8 isrepresented schematically by the directional arrow 203. Subsequentrecovery of the hydrogen-containing gas 8 is represented schematicallyby the directional arrow 204 of FIG. 6 .

Several components of a system 100 for producing, storing andsubsequently recovering a hydrogen-containing gas are shown in bothFIGS. 5 and 6 . Hydrogen-gas-pumping arrangements 90 are provided influid communication with the reservoir 35 via wellbore 10. The pumpingarrangements 80 include pumps and compressors, piping (e.g., piping 12),power equipment, and other equipment as necessary for injecting thehydrogen gas 8. The pumping arrangements 90 are configured to inject thehydrogen 8 at a pressure higher than a current shut-in gas pressure atthe wellbore 10. Gas-recovery equipment 80 is also in fluidcommunication with the reservoir 35 though the wellbore 10. Thegas-recovery equipment 80 is operative to recover a portion of thestored hydrogen-containing gas 8 through the wellbore 10. The system 100is operable such that the recovered portion of the hydrogen-containinggas 8 has an H₂ molar fraction of at least 85%. In various examples, theH₂ molar fraction is at least 85%, or at least 86%, or at least 87%, orat least 88%, or at least 89%, or at least 90%, or at least 91%, or atleast 92%, or at least 93%, or at least 94%, or at least 95%, or atleast 96%, or at least 97%, or at least 98%, or at least 99%. Inembodiments, the remainder of the gas, i.e., after subtracting the H₂molar fraction, is at least predominantly CH₄. In some embodiments, thepumping arrangements 90 are operative to inject the hydrogen-containinggas 8 at a pressure that is at least 500 PSI higher than the currentshut-in gas pressure at the wellbore 10. In some embodiments, thepumping arrangements 90 are operative to inject the hydrogen-containinggas 8 at a pressure that is no more than 100 PSI less than a maximumwellhead pressure of the gas-recovery process of the reservoir 35. Insome embodiments, the pumping arrangements 90 are operative to injectthe hydrogen-containing gas 8 at a pressure that is no more than 50 PSIless than the maximum wellhead pressure.

In some embodiments, the system 100 additionally includes surfacegeophysical-monitoring equipment 95 for determining whether hydraulicfractures, e.g., one or more hydraulic fractures, are being extended bythe hydrogen injection. Suitable examples of surfacegeophysical-monitoring equipment include microseismic arrays andtiltmeters. In some embodiments, the system 100 additionally includes atracer-gas facility 96 for adding a gas-phase tracer to the injectedhydrogen gas 8.

Referring now to FIG. 7 , a method is disclosed for operating akerogen-rich unconventional gas reservoir characterized by there beingmultiple hydraulically-fractured wells drilled thereinto. As illustratedby the flowchart in FIG. 7 , the method comprises Steps S01, S02, S03,and S04, which are discussed in the following paragraphs.

Step S01: recovering a methane-containing gas 5 from a firsthydraulically-fractured well 11 ₁. In this step, natural gas 5 isrecovered through the wellbore 10 from the reservoir 35, including fromthe hydraulic fractures 32, and processed by gas recovery equipment 80which is in fluid communication with the wellbore 10 at the wellhead 18.The recovery of the methane-containing gas 5 is further discussedhereinabove with reference to FIGS. 3 and 4 .

Step S02: steam-methane reforming the recovered methane-containing gas 5to yield a hydrogen gas 8 and an inorganic carbon-containing gas 9. Inembodiments, the steam-methane reforming of Step S02 includes performingthe water-gas shift to convert at least a majority of the CO produced inthe reforming to CO₂. An example of a suitable steam-methane reformerfor performing the reforming is steam-methane reformer 42 shown in FIG.2 .

In a non-limiting and illustrative example of the reforming process, thefour gas-producing wells 11 ₁, 11 ₄ (of FIG. 2 ) and two othergas-producing wells 11 (not shown) produce 400 tons of methane per day.According to the example, all the recovered gas 5 is routed to the SMR42 for reforming. For the four gas-producing wells, each producing 100tons of methane per day, totaling 400 tons per day, about 900 tons ofwater and over 1,000 MWh of heat are added per day in the steam-methanereforming and water-gas shift processes. The SMR 42 of this exampleproduces 200 tons of hydrogen gas 8 per day, and about 1,100 tons ofCO₂. In some embodiments, the SMR 42 uses energy produced at least inpart from a portion of recovered hydrogen-containing gas.

Step S03: injecting at least a portion of the hydrogen gas 8 into asecond hydraulically-fractured well 11 ₂. As shown in the example ofFIG. 5 , where injection of the hydrogen 8 is represented schematicallyby the directional arrow 203, hydrogen-gas-pumping arrangements 90 areprovided in fluid communication with the reservoir 35 via wellbore 10.The skilled artisan will understand that Step S03 can involve one ormore preparatory steps before injecting hydrogen into the well, e.g.,for the first time after a period during which the well was used torecover natural gas 5 or a hydrogen-containing gas 8. For example, itcan be desirable to close valves at the surface to cause pressure in thereservoir 35 to reach an equilibrium pressure. This allows time for thewellhead pressure to increase from a flowing wellhead pressure to ashut-in wellhead pressure. Over a period of time, e.g., weeks, theshut-in wellhead pressure rises to an equilibrium pressure that isapproximately equal to reservoir pressure. The injection of the hydrogengas 8, e.g., pure H₂, or a hydrogen-containing gas that includes atleast 99% H₂ or at least 98% H₂, or at least 97% H₂, or at least 96% H₂,or at least 95% H₂, is at a pressure higher than the current gaspressure at the wellhead 18, e.g., the shut-in wellhead pressure at astabilized reservoir-equilibrium pressure, so as to ensure that thehydrogen gas 8 propagates throughout the well, i.e., including thehydraulic fractures 32 and natural cracks. In embodiments, the secondhydraulically-fractured well 11 ₂ is partially depleted by amethane-containing-gas recovery process characterized by (i) a maximumflow rate and (ii) a minimum flow rate that is not more than 20% of themaximum flow rate.

Step S04: injecting at least a portion of the inorganiccarbon-containing gas 9 into a third hydraulically-fractured well 11 ₃.In embodiments, the third hydraulically-fractured well 11 ₃ is partiallydepleted by a methane-containing-gas recovery process characterized by(i) a maximum flow rate and (ii) a minimum flow rate that is at least10% of the maximum flow rate. The inorganic carbon-containing gas caninclude carbon dioxide (CO₂) and/or carbon monoxide (CO) in anycombination.

In some embodiments, as illustrated by the flow chart in FIG. 8 , themethod additionally comprises the following step:

Step S05: recovering, from the second hydraulically-fractured well 11 ₂,a hydrogen-containing gas 8 having an H₂ molar fraction of at least 85%.In some embodiments, the hydrogen-containing gas 8 has an H₂ molarfraction of at least 90%, or at least 95%, or at least 97%. The H₂ molarfraction of the recovered gas can be directly impacted by the selectionof the reservoir 35, e.g., selection of a kerogen-rich reservoir, and/orselection of a kerogen-rich reservoir with low permeability. The H₂molar fraction of the recovered gas can be directly impacted by theminimum pressure of the gas-depletion.

The H₂ molar fraction of the recovered gas can be directly impacted bythe conditions prevalent in the well 11 ₂ at the time that the gasrecovery from the well 11 ₂ was stopped for initiating the injection ofhydrogen gas into the reservoir, e.g., what flowrate and/or pressure wasprevalent in the well 11 ₂ at that time. In embodiments, the transitionto injection of hydrogen can be chosen to correspond to a state of thereservoir in which pore methane and kerogen-adsorbed methane is largelyalready recovered, such that the hydrogen gas replaces the methane inthe faster-recovery locations of the shale formation.

As was shown in the example of FIG. 6 , where recovery of thehydrogen-containing gas 8 is represented schematically by thedirectional arrow 204, hydrogen-gas-recovery equipment 80 is provided influid communication with the reservoir 35 via wellbore 10. The recoveredhydrogen-containing gas 8 can include bulk-phase H₂ in hydraulicfractures, H₂ in kerogen pore spaces, H₂ adsorbed on kerogen surfaces,H₂ dissolved in kerogen, and/or bulk-phase H₂ contained in thenon-organic pores or adsorbed on clays of the matrix of the geologicalformation 30.

In some embodiments, as illustrated by the flow chart in FIG. 9 , themethod additionally comprises the following step:

Step S06: generating electricity from at least a portion of therecovered hydrogen-containing gas 8. In some embodiments, theelectricity is generated using a gas turbine, e.g., gas turbine 45 ofFIG. 2 . In some embodiments, the electricity is generated using areciprocating engine. In some embodiments, electricity is generatedusing a fuel cell, e.g., fuel cell 46 of FIG. 2 . In some embodiments,at least a portion of the generated electricity is used in thesteam-methane reforming of Step S02. In some embodiments, a majority ofthe generated electricity is used in the steam-methane reforming of StepS02. In some embodiments, a majority of the generated electricity isdelivered to a distribution network of an electric utility, e.g., viatransmission arrangements 48, and, for example, is sold commercially.Transmission arrangements 48 can include electrical subsystem equipmentsuch as transformers, power conditioning equipment, inverters (forelectricity generated by fuel cells 46), etc. In some embodiments, anyor all the electricity can be generated from a gas mixture comprisingmethane and hydrogen.

In some embodiments, as illustrated by the flow chart in FIG. 10 , themethod additionally comprises the following step:

Step S07: performing surface geophysical monitoring to determine whetherhydraulic fractures 32 are being extended by the injecting of thehydrogen gas 8 or of the inorganic carbon-containing gas 9. According tonon-limiting examples, surface geophysical monitoring can include theuse of surface geophysical monitoring equipment 95 such as microseismicarrays or tiltmeters.

In some embodiments, as illustrated by the flow chart in FIG. 11 , themethod additionally comprises the following step:

Step S08: employing a gas phase tracer to verify that hydraulicfractures 32 of a given hydraulically-fractured well 11 drilled into thegas reservoir 35 do not extend into a fracture 32 that is in fluidcommunication with a different hydraulically-fractured well 11. Suitablegas phase tracers include tritiated hydrogen such as HT or T₂ in therange of 3 to 30×10{circumflex over ( )}10 Becquerel (Bq) that may bedetected at extremely low concentrations in nearby production wells.According to a non-limiting example, a tracer-gas facility 96 for addinga gas-phase tracer to the injected hydrogen gas 8 is provided at or nearthe wellhead 18.

Referring now to FIG. 12 , a system 100 for producing, storing andsubsequently recovering a hydrogen-containing gas includes asteam-methane reformer (SMR) 42. In the embodiment illustrated in FIG.12 , the SMR 42 is located onsite, i.e., at or in proximity to akerogen-rich unconventional gas reservoir 35. ‘In proximity’ can meanwithin 10 km, or within 50 km, or within 100 km, or within 250 km, orwithin 500 km of the gas reservoir. In some embodiments, the SMR 42 canbe located onsite at a kerogen-rich unconventional gas reservoir 35which is no longer used for producing natural gas.

The unconventional gas reservoir 35 is characterized by having multiplewells 11 drilled thereinto; in the example of FIG. 12 , the multiplewells 11 include (at least) hydraulically-fractured wells 11 ₂ and 11 ₃drilled into the reservoir 35. A single SMR 42 can serve one or morewells 11, i.e., reform the methane gas recovered from one or more wells11, drilled in reservoir 35. The skilled artisan will understand thatthese wells are illustrative in nature and in practicing the embodimentsit is likely to employ an unconventional gas reservoir having many morewells drilled into it. In some embodiments, a single SMR 42 serves some,many, most, or all of the gas-producing (including formerlygas-producing) wells 11 drilled into a reservoir 35.

The hydraulic and natural fractures in the respective wells areindicated by the arrows 32. Hydrogen-gas-pumping arrangements 90 andhydrogen-gas-recovery equipment 80 are both provided in fluidcommunication with the reservoir 35 via the wellbore of well 11 ₂,respectively for injection of hydrogen into the well and for laterrecovery of the stored hydrogen. The pumping arrangements 90 includepumps and compressors, piping, power equipment, and other equipment asnecessary for injecting the hydrogen gas into the well. The pumpingarrangements 90 are configured to inject the hydrogen at a pressurehigher than a current shut-in gas pressure at the wellbore of well 11 ₂.Well 11 ₃ is a partially depleted well, being used for injecting aninorganic carbon-containing gas, e.g., CO₂ and/or CO, into the well forstorage. The CO₂ and CO, which are products of the steam-reformingprocess, can be stored in the partially depleted gas wells indefinitely.CO/CO₂-gas-pumping arrangements 91 are provided in fluid communicationwith the reservoir 35 via the wellbore of well 11 ₃, for injection ofthe inorganic carbon-containing gas into the well.

In the non-limiting example illustrated in FIG. 12 , the SMR 42 receivesnatural gas (methane) from offsite, e.g., through pipeline 73 or byother transportation means (not shown) such as vehicles and/or ships.The main products of the steam reforming process, H₂ and CO/CO₂, aredelivered to respective pumping arrangements 90 and 91, by piping thegases from the SMR 42, as indicated in FIG. 12 by 901 and 910,respectively. In some implementations, a majority, or even all, of thehydrogen gas produced by the SMR 42 is piped (as indicated by arrow902), for purposes other than storage in the well 11 ₂. The system 100can include a separator 60 for separating H₂ from other gases,especially CH₄. Non-limiting examples of suitable separators include anembedded membrane in a catalyst tube or a shell-and-tube configuration.

In a non-limiting example, some, or a majority, or even all, of theproduced hydrogen gas is used to generate electricity onsite, forexample by being piped, as indicated by arrow 903, to a gas turbine 45or to a fuel cell 46. In another non-limiting example, some, or amajority, or even all, of the produced hydrogen gas, is sent offsite viaa pipeline 71. As shown in FIG. 12 , a hydrogen-containing gas recoveredfrom well 11 ₂ following recovery from storage therein, indicated byarrow 900, is sent to the separator 60, as, for separation of the H₂from the CH₄, and/or is sent, as indicated by arrow 903, to a gasturbine 45 for generating electricity, either with or without separationof the methane at the separator 60. Hydrogen-containing gas exiting theseparator 60, as indicated by arrow 904, yields H₂ which can be used togenerate electricity, for example in the fuel cell 46 (or in the gasturbine 45), or can be shipped offsite by pipeline 71. The CH₄ separatedfrom the H₂ at the separator can be shipped offsite by pipeline 72, orcan be sent to the SMR 42. Electricity generated onsite is deliveredoffsite by electricity transmission arrangements (not shown). Any or allof the foregoing functions and features of the system can be combined inany manner in a single embodiment, and not every embodiment includesevery function or feature discussed.

In some embodiments, e.g., as illustrated in FIGS. 5 and 6 , the system100 additionally includes surface geophysical-monitoring equipment 95for determining whether hydraulic fractures, e.g., one or more hydraulicfractures, are being extended by the hydrogen injection. Suitableexamples of surface geophysical-monitoring equipment includemicroseismic arrays and tiltmeters. In some embodiments, the system 100additionally includes a tracer-gas facility 96 for adding a gas-phasetracer to the injected hydrogen gas 8.

In some embodiments, e.g., as illustrated in FIGS. 2B and 2C, gases,e.g., H₂ and/or CH₄, are combusted to create the heat necessary for thesteam-methane reforming process. For example, H₂+CH₄ from H₂-storagewells such as H₂-storage well 11 ₂ of FIG. 2A, CH₄ received by pipeline,or H₂ yielded by the SMR facility 42 itself can be used for combustion.Any gas flows for combustion can first be routed to a separator 60 (alsoshown in FIG. 12 ). For example, if the combustion process requires onlyhydrogen, then the H₂/CH₄ flow 900 is routed first to a separatorfacility 60 and thence to the combustion facilities 43, 44 of FIG. 2B-C,which can also be provided in system 100 of FIG. 12 . Examples ofsuitable mixtures of combustion-fuel gases include a mix that comprisesat least 15% H₂, or at least 50% H₂, or at least 85% H₂, or at least 90%H₂, or at least 95% H₂, or at least 98% H₂ (all percentages by molarweight).

System 100 of FIG. 12 can also include the blending facility 49 of FIG.2C, configured to produce a blended stream comprising a fixed ratiobetween two or more gases, e.g., methane and hydrogen at a fixed ratio.In another example shown in FIG. 2A, the gas flows of FIG. 2B can firstbe routed to a blending facility 49 in order to achieve a desired mix ofcombustion-fuel gases, indicated in FIG. 2C by arrow 922. for deliveryto the boiler 43 and/or burners 44 of the SMR facility 42. As shown inFIG. 2C, for purposes delivering a blended gas, the blending facility 49can be arranged in fluid communication with an electrical generator suchas a gas turbine 45, or a pipeline 75 for off-site transport of theblended gas. The blending facility 49 can also be arranged to deliver apre-determined mix to a gas-fueled compressor 93.

Referring now to FIG. 13 , a method is disclosed for operating akerogen-rich unconventional gas reservoir characterized by there beingmultiple hydraulically-fractured wells drilled thereinto. As illustratedby the flowchart in FIG. 7 , the method comprises Steps S11, S12, S13,and S14, which are discussed in the following paragraphs.

Step S11: receiving a methane-containing gas 5 at an SMR, e.g., the SMR42 of FIG. 12 . In embodiments, the gas 5 is received from offsite,e.g., through pipeline 73 of FIG. 12 , or by other transportationconveyances (not shown) such as vehicles and/or ships. In someembodiments, Step S11 is combined with Step S01, such that the SMR 42receives gas 5 from both offsite onsite sources, i.e., from additionalwells 11 servicing the reservoir 35 as shown in FIG. 2 .

Step S12: steam-methane reforming gas 5 received in Step S11 (including,optionally, in combination with Step S01) to yield a hydrogen gas 8 andan inorganic carbon-containing gas 9. In embodiments, the steam-methanereforming of Step S12 includes performing the water-gas shift to convertat least a majority of CO produced in the reforming to CO₂. An exampleof a suitable steam-methane reformer for performing the reforming issteam-methane reformer 42 shown in FIG. 12 . In a non-limiting andillustrative example of the reforming process, pipeline 73 delivers1,000 tons of methane per day. According to the example, all of thereceived gas 5 is routed to the SMR 42 for reforming. Over 2,000 tons ofwater are added per day in the steam-methane reforming and water-gasshift processes, and over 2,500 MWh of heat. In some embodiments, theSMR 42 uses energy produced at least in part from a portion of recoveredhydrogen-containing gas. The SMR 42 of the example produces 500 tons ofhydrogen gas 8 per day, and about 2,700 tons of CO₂.

Step S13: injecting at least a portion of the hydrogen gas 8 into afirst hydraulically-fractured well 11 ₂. As was shown in the example ofFIG. 5 , where injection of the hydrogen 8 is represented schematicallyby the directional arrow 203, hydrogen-gas-pumping arrangements 90 areprovided in fluid communication with the reservoir 35 via wellbore 10.The skilled artisan will understand that Step S13 can involve one ormore preparatory steps before injecting hydrogen into the well, e.g.,for the first time after a period during which the well 11 ₂ was used torecover natural gas 5 or a hydrogen-containing gas 8. For example, itcan be desirable to close valves at the surface to cause pressure in thereservoir 35 to reach an equilibrium pressure. This allows time for thewellhead pressure to increase from a flowing wellhead pressure to ashut-in wellhead pressure. Over a period of time, e.g., weeks, theshut-in wellhead pressure rises to an equilibrium pressure that isapproximately equal to reservoir pressure. The injection of the hydrogengas 8, e.g., pure H₂, or a hydrogen-containing gas that includes atleast 99% H₂ or at least 98% H₂, or at least 97% H₂, or at least 96% H₂,or at least 95% H₂, is at a pressure higher than the current gaspressure at the wellhead 18, e.g., the shut-in wellhead pressure at astabilized reservoir-equilibrium pressure, so as to ensure that thehydrogen gas 8 propagates throughout the well, i.e., including thehydraulic fractures 32 and natural cracks. In embodiments, the secondhydraulically-fractured well 11 ₂ is partially depleted by amethane-containing-gas recovery process characterized by (i) a maximumflow rate and (ii) a minimum flow rate that is not more than 20% of themaximum flow rate.

Step S14: injecting at least a portion of the inorganiccarbon-containing gas 9 into a second hydraulically-fractured well 11 ₃.In embodiments, the second hydraulically-fractured well 11 ₃ ispartially depleted by a methane-containing-gas recovery processcharacterized by (i) a maximum flow rate and (ii) a minimum flow ratethat is at least 10% of the maximum flow rate. The inorganiccarbon-containing gas can include carbon monoxide (CO) and/or carbondioxide (CO₂) in any combination.

In some embodiments, as illustrated by the flow chart in FIG. 14 , themethod additionally comprises the following step:

Step S15: recovering, from the first hydraulically-fractured well 11 ₂,a hydrogen-containing gas 8 having an H₂ molar fraction of at least 85%.In some embodiments, the hydrogen-containing gas 8 has an H₂ molarfraction of at least 90%, or at least 95%, or at least 97%. The H₂ molarfraction of the recovered gas can be directly impacted by the selectionof the reservoir 35, e.g., selection of a kerogen-rich reservoir, and/orselection of a kerogen-rich reservoir with low permeability. The H₂molar fraction of the recovered gas can be directly impacted by theminimum pressure of the gas-depletion

The H₂ molar fraction of the recovered gas can be directly impacted bywhen (e.g., by what flowrate and/or pressure was prevalent in the well11 ₂ the gas recovery from the well 11 ₂ was ceased for initiating theinjection of hydrogen gas into the reservoir. In embodiments, thetransition to injection of hydrogen can be chosen to correspond to astate of the reservoir in which pore methane and kerogen-adsorbedmethane is largely already recovered, such that the hydrogen gasreplaces the methane in the faster-recovery locations of the shaleformation.

As shown in the example of FIG. 6 , where recovery of thehydrogen-containing gas 8 is represented schematically by thedirectional arrow 204, hydrogen-gas-recovery equipment 80 is provided influid communication with the reservoir 35 via wellbore 10. The recoveredhydrogen-containing gas 8 can include bulk-phase H₂ in hydraulicfractures, H₂ in kerogen pore spaces, H₂ adsorbed on kerogen surfaces,H₂ dissolved in kerogen, and/or bulk-phase H₂ contained in thenon-organic pores or adsorbed on clays of the matrix of the geologicalformation 30.

In some embodiments, as illustrated by the flow chart in FIG. 15 , themethod additionally comprises the following step:

Step S16: generating electricity from at least a portion of therecovered hydrogen-containing gas 8. In some embodiments, theelectricity is generated using a gas turbine, e.g., gas turbine 45 ofFIG. 12 . In some embodiments, the electricity is generated using areciprocating engine. In some embodiments, electricity is generatedusing a fuel cell, e.g., fuel cell 46 of FIG. 12 . In some embodiments,at least a portion of the generated electricity is used in thesteam-methane reforming of Step S12. In some embodiments, a majority ofthe generated electricity is delivered to a distribution network of anelectric utility, e.g., via transmission arrangements 48, and, forexample, is sold commercially. Transmission arrangements 48 can includeelectrical subsystem equipment such as transformers, power conditioningequipment, inverters (for electricity generated by fuel cells 46), etc.In some embodiments, any or all of the electricity is generated from agas mixture comprising methane and hydrogen.

In some embodiments, as illustrated by the flow chart in FIG. 16 , themethod additionally comprises the following step:

Step S19: separating the yielded hydrogen gas from the inorganiccarbon-containing gas yielded by the steam-methane reforming of StepS12. According to some embodiments, a system 100 according to any one ofFIGS. 2A, 2B, 2C and 12 includes a separator facility (not illustrated)for separating hydrogen gas from an inorganic carbon-containing gas.Non-limiting examples of suitable technologies for performing theseparation include pressure swing adsorption method, a cryogenicdistillation method at a low temperature, and through membraneseparators or porous ceramics.

In some embodiments, as illustrated by the flow chart in FIG. 17 , themethod additionally comprises the following step:

Step S20: further recovering, from the second hydraulically-fracturedwell 11 ₃, a methane-containing gas 5. The secondhydraulically-fractured well 11 ₃, is the well into which the inorganiccarbon-containing gas (CO₂ and/or CO) is injected into in Step S14. WhenCO₂ is injected into a partially-depleted unconventional well, itdisplaces CH₄ from the kerogen. Thus, when sequestering CO₂, if the well11 is shut-in for a period of time, it is possible to produce additionalCH₄ from the well where the CO₂ is stored. This step can be repeateduntil the well is fully depleted of CH₄. CO₂ recovered with the CH₄ canbe returned to the well after separation.

In some embodiments, as illustrated by the flow chart in FIG. 18 , themethod additionally comprises the following step:

Step S17: performing surface geophysical monitoring to determine whetherhydraulic fractures 32 are being extended by the injecting of thehydrogen gas 8 or of the inorganic carbon-containing gas 9. According tonon-limiting examples, surface geophysical monitoring can include theuse of surface geophysical monitoring equipment 95 such as microseismicarrays or tiltmeters.

In some embodiments, as illustrated by the flow chart in FIG. 19 , themethod additionally comprises the following step:

Step S18: employing a gas phase tracer to verify that hydraulicfractures 32 of a given hydraulically-fractured well 11 drilled into thegas reservoir 35 do not extend into a fracture 32 that is in fluidcommunication with a different hydraulically-fractured well 11. Suitablegas phase tracers include tritiated hydrogen such as HT or T₂ in therange of 3 to 30×10{circumflex over ( )}10 Becquerel (Bq) that may bedetected at extremely low concentrations in nearby production wells.According to a non-limiting example, a tracer-gas facility 96 for addinga gas-phase tracer to the injected hydrogen gas 8 is provided at or nearthe wellhead 18.

Referring now to FIG. 20 , a method is disclosed for operating akerogen-rich unconventional gas reservoir characterized by there beingmultiple hydraulically-fractured wells drilled thereinto. As illustratedby the flowchart in FIG. 20 , the method comprises six method steps S21. . . S26.

Step S21: receiving a methane-containing gas 5 at an SMR, e.g., the SMR42 of FIG. 12 . In some embodiments, the gas 5 is received from offsite,e.g., through pipeline 73 of FIG. 12 , or by other transportationconveyances (not shown) such as vehicles and/or ships. In someembodiments, Step S21 additionally or alternatively includes performingthe gas recovery activity of Step S01, such that the SMR 42 receives gas5 from offsite, from onsite, or from both, either simultaneously or atdifferent times. Gas received onsite is from wells 11 drilled in thereservoir 35 as illustrated in FIG. 2 , where wells 11 ₁ and 11 ₄ areshown as producing gas.

Step S22: steam-methane reforming gas 5 received in Step S21 to yield ahydrogen gas 8 and an inorganic carbon-containing gas 9. In embodiments,the steam-methane reforming of Step S22 includes performing thewater-gas shift to convert at least a majority of CO produced in thereforming to CO₂. An example of a suitable steam-methane reformer forperforming the reforming is steam-methane reformer 42 shown in eitherFIG. 2 or FIG. 12 . In a non-limiting and illustrative example of thereforming process, the SMR 42 receives 1,000 tons of methane per dayfrom onsite and/or offsite sources. According to the example, all of thereceived gas 5 is routed to the SMR 42 for reforming. Over 2,000 tons ofwater are added per day in the steam-methane reforming and water-gasshift processes, and over 2,500 MWh of heat. In some embodiments, theSMR 42 uses energy produced at least in part from a portion of recoveredhydrogen-containing gas. The SMR 42 of the example produces 500 tons ofhydrogen gas 8 per day, and about 2,700 tons of CO₂.

Step S23: injecting at least a portion of the hydrogen gas 8 into asecond hydraulically-fractured well 11 ₂. As was shown in the example ofFIG. 5 , where injection of the hydrogen 8 is represented schematicallyby the directional arrow 203, hydrogen-gas-pumping arrangements 90 areprovided in fluid communication with the reservoir 35 via wellbore 10.The skilled artisan will understand that Step S23 can involve one ormore preparatory steps before injecting hydrogen into the well, e.g.,for the first time after a period during which the well was used torecover natural gas 5 or a hydrogen-containing gas 8. For example, itcan be desirable to close valves at the surface to cause pressure in thereservoir 35 to reach an equilibrium pressure. This allows time for thewellhead pressure to increase from a flowing wellhead pressure to ashut-in wellhead pressure. Over a period of time, e.g., weeks, theshut-in wellhead pressure rises to an equilibrium pressure that isapproximately equal to reservoir pressure. The injection of the hydrogengas 8, e.g., pure H₂, or a hydrogen-containing gas that includes atleast 99% H₂ or at least 98% H₂, or at least 97% H₂, or at least 96% H₂,or at least 95% H₂, is at a pressure higher than the current gaspressure at the wellhead 18, e.g., the shut-in wellhead pressure at astabilized reservoir-equilibrium pressure, so as to ensure that thehydrogen gas 8 propagates throughout the well, i.e., including thehydraulic fractures 32 and natural cracks. In embodiments, the secondhydraulically-fractured well 11 ₂ is partially depleted by amethane-containing-gas recovery process characterized by (i) a maximumflow rate and (ii) a minimum flow rate that is not more than 20% of themaximum flow rate.

Step S24: injecting at least a portion of the inorganiccarbon-containing gas 9 into a third hydraulically-fractured well 11 ₃.In embodiments, the third hydraulically-fractured well 11 ₃ is partiallydepleted by a methane-containing-gas recovery process characterized by(i) a maximum flow rate and (ii) a minimum flow rate that is at least10% of the maximum flow rate. The inorganic carbon-containing gas caninclude carbon monoxide (CO) and/or carbon dioxide (CO₂) in anycombination.

Step S25: recovering, from the second hydraulically-fractured well 11 ₂,a hydrogen-containing gas 8 having an H₂ molar fraction of at least 85%.In some embodiments, the hydrogen-containing gas 8 has an H₂ molarfraction of at least 90%, or at least 95%, or at least 97%. The H₂ molarfraction of the recovered gas can be directly impacted by the selectionof the reservoir 35, e.g., selection of a kerogen-rich reservoir, and/orselection of a kerogen-rich reservoir with low permeability. The H₂molar fraction of the recovered gas can be directly impacted by theminimum pressure of the gas-depletion.

The H₂ molar fraction of the recovered gas can be directly impacted bywhen (e.g., by what flowrate and/or pressure was prevalent in the well11 ₂ the gas recovery from the well 11 ₂ was ceased for initiating theinjection of hydrogen gas into the reservoir. In embodiments, thetransition to injection of hydrogen can be chosen to correspond to astate of the reservoir in which pore methane and kerogen-adsorbedmethane is largely already recovered, such that the hydrogen gasreplaces the methane in the faster-recovery locations of the shaleformation.

As was shown in the example of FIG. 6 , where recovery of thehydrogen-containing gas 8 is represented schematically by thedirectional arrow 204, hydrogen-gas-recovery equipment 80 is provided influid communication with the reservoir 35 via wellbore 10. The recoveredhydrogen-containing gas 8 can include bulk-phase H₂ in hydraulicfractures, H₂ in kerogen pore spaces, H₂ adsorbed on kerogen surfaces,H₂ dissolved in kerogen, and/or bulk-phase H₂ contained in thenon-organic pores or adsorbed on clays of the matrix of the geologicalformation 30.

Step S26: generating electricity from at least a portion of therecovered hydrogen-containing gas 8. In some embodiments, theelectricity is generated using a gas turbine, e.g., gas turbine 45 ofFIG. 12 . In some embodiments, the electricity is generated using areciprocating engine. In some embodiments, electricity is generatedusing a fuel cell, e.g., fuel cell 46 of FIG. 12 . In some embodiments,at least a portion of the generated electricity is used in thesteam-methane reforming of Step S12. In some embodiments, a majority ofthe generated electricity is used in the steam-methane reforming of Step12. In some embodiments, a majority of the generated electricity isdelivered to a distribution network of an electric utility, e.g., viatransmission arrangements 48, and, for example, is sold commercially.Transmission arrangements 48 can include electrical subsystem equipmentsuch as transformers, power conditioning equipment, inverters (forelectricity generated by fuel cells 46), etc. In some embodiments, anyor all of the electricity is generated from a gas mixture comprisingmethane and hydrogen.

Any of the disclosed embodiments can be combined in any practicalmanner. In any of the disclosed methods, not all of the steps need beperformed Any of the steps of any of the disclosed methods can becombined in any way to create combinations not explicitly disclosed andany such combinations are within the scope of the invention.

Unless otherwise specified, the term ‘portion’ as used in the presentdisclosure means a non-zero fraction that is less than 1. Unlessotherwise specified, the term ‘at least a portion’ means a non-zerofraction can also be 1.

According to further embodiments of the invention, an unconventional gasreservoir can be suitable for long-term and/or short-term storage ofhydrogen gas after partial depletion of the natural gas. The timeline ofFIG. 21 shows a sequence of stages associated with the use of apartially depleted unconventional gas reservoir for storage and recoveryof hydrogen in accordance with embodiments. In a first stage, beforeTime=T₀, a suitable gas-containing reservoir is selected, e.g., based onone or more technical and/or economic selection criteria, and a deephorizontal wellbore is established in the reservoir. Non-limitingexamples of technical selection criteria include, and not exhaustively:low permeability, e.g., permeability lower than 10⁻¹ millidarcy (mD),lower than 10⁻² niD, lower than 10⁻³ mD, or lower than 10⁻⁴ mD;proportion of organic matter (i.e., kerogen), e.g., at least 1% kerogen,at least 2% kerogen, or at least 3% kerogen; and distribution of porevolumes in the kerogen.

In a second stage, between Time=T₀ and Time=T₁, the reservoir ishydraulically fractured. The deep horizontal wellbore is perforated forhydraulic fracturing, e.g., by a perforating gun. A fracturing fluid isinjected under pressure through a horizontal wellbore into thegeological formation to effect the fracturing by propagation andexpansion of cracks in the rock structure. The hydraulic fracturingprocess is used to facilitate and/or accelerate the recovery of gas fromthe reservoir by opening up cracks in the deep shale formations. As isknown in the art, successive sections of the reservoir along thewellbore are fractured sequentially and not simultaneously. An exampleof a suitable fracturing fluid is a mixture of water, a proppant such assand or a ceramic, and/or a chemical or polymer to improve a flowcharacteristic such as the water's surface friction and/or to act as alubricant. In other examples, a suitable fracturing fluid can include anenergized fluid, e.g., a fluid including at least one compressed orcompressible gas-phase material, or an oil-based fluid.

In a third stage, between Time=T₁ and Time=T₂, natural gas is recoveredfrom the hydraulically-fractured reservoir. The gas recovery processover time is characterized by a maximum flow rate of FLOW_(MAX), and aminimum flow rate of FLOW_(MIN).

In a fourth stage, between Time=T₂ and Time=T₃, hydrogen gas is injectedinto the reservoir. In embodiments, the transition from the third stageto the fourth stage, at Time=T₂, is based on a trigger criterion. Thetrigger criterion can include a trigger criterion that corresponds togas production (recovery) falling over time to a production triggercriterion. An example of a production trigger criterion, e.g., inmillions of cubic feet per day (MCF/day), is a flow-rate triggercriterion FLOW_(TRIGGER). When a current flow rate FLOW_(CURRENT)reaches the trigger criterion FLOW_(TRIGGER) in a downward trend, e.g.,in an exponentially-declining trend, operation of the reservoirtransitions to injecting compressed hydrogen for long- and/or short-termstorage.

In a fifth stage, between Time=T₃ and Time=T₄, stored hydrogen gas isrecovered from the reservoir. The recovered hydrogen gas is mostly purehydrogen, i.e., has an H₂ molar fraction of at least 85%, or at least86%, or at least 87%, or at least 88%, or at least 89%, or at least 90%,or at least 91%, or at least 92%, or at least 93%, or at least 94%, orat least 95%, or at least 96%, or at least 97%, or at least 98%, or atleast 99%. The remainder of the recovered gas mix can include methane,other hydrocarbon gases such as ethane and propane, and non-hydrocarbongases such as carbon dioxide and nitrogen.

In a sixth stage, after Time=T₄, the injecting and recovering ofhydrogen can be cycled. The sixth stage can thus be considered arepetition or cycling of the fourth and fifth stages. In someembodiments, when the hydrogen recovery of the fifth stage reaches ahydrogen-production trigger criterion, operation of reservoir reverts toinjecting hydrogen, inter alia to increase pressure and improve futurehydrogen recovery volume. In some embodiments, hydrogen is cycled on adaily basis, meaning that within a single diurnal cycle, hydrogen isinjected, and then recovered. The diurnal cycle can repeat indefinitely.In some such embodiments, the fourth-stage injection of hydrogen can beup to a ‘base level’, on top of which there is a daily cycle offluctuation, so that the daily recovery cycle is at a sufficiently highpressure to ensure rapid recovery.

Any or all of the times T₀, T₁, T₂, T₃ and T₄ can be points in time orperiods of time, for example, days, weeks or months.

Referring now to FIG. 22 , a method is disclosed for storing hydrogengas in a kerogen-rich geological formation. As illustrated by theflowchart in FIG. 22 , the method comprises Steps S101, S102, S103, S104and S105, which are discussed in the following paragraphs.

Step S101

Step S101 includes injecting a fracturing fluid through a horizontalwellbore into the geological formation to cause fracturing within thegeological formation. Arrangements for injecting a fracturing fluid intoa geological formation are illustrated schematically in FIG. 23 . Ageological formation 30, shown in accordance with the descriptionhereinabove of the second stage between Time=T₀ and Time=T₁, includes anorganic-rich shale deposit (also called a shale formation). Hydraulicfracturing equipment 70 is disposed at a wellhead 18. The wellhead 18 islocated at a wellpad 19 and is in fluid communication with anunconventional gas reservoir 35 located within the shale formation 30,which in the non-limiting example of FIG. 22 is below the water table27.

The wellbore 10, including perforated casing, is horizontally-orientedat the depth of the shale formation 30, and can extend horizontally fortens, hundreds or thousands of meters. As indicated by the directionalarrow 201, a hydraulic-fracturing fluid 3 is injected into (and through)the wellbore 10 and thence into fractures 32. The injecting is effectiveto increase pressure at the target depth of the reservoir 35, e.g.,based on the depth of the wellbore, to exceed that of the fracturegradient of the rock. At a fracture-initiating pressure known as a‘breakdown pressure’, the deep rock surrounding the wellbore 10 crackswith pressure. Once fracturing is initiated, pressure at the wellhead 18drops and then starts increasing, as the fracturing fluid 3 permeatesthe rock, further extending the fractures. This occurs at thefracture-extending pressure FRAC_(EXT). Fractures predominantlyperpendicular to the wellbore may reach lengths of a few hundred feetlong; the height of the fractures 32 is controlled by the stresses inthe rock formations above and below the wellbore.

FIG. 23 illustrates only a single well, but a single geologicalformation 30 or a single unconventional gas reservoir 35 can be servicedby multiple wells, as shown in FIG. 24 . FIG. 24 illustrates multiplewells (indicated by wellbores 10) at each wellpad 19, and multiplewellpads 19 servicing the gas reservoir 35. In the non-limiting exampleof FIG. 24 , gas flows through a network of transmission nodes to acentral treatment hub that services the multiple wells. The example ofFIG. 24 shows 8 wells, i.e., wellbores 10, operating from each wellpad19. In other examples, not illustrated, there can be any number ofwells, such as for example, 16, 32 or 64 wells. Each well comprises awellhead 18 and a wellbore 10. Pressure and flow measurements may bemade using pressure and flow gauges at the wellhead 18 while flowing orduring shut-in. Pressure may also be measured downhole using downholepressure gauges.

Step S102

Step S102 includes recovering a methane-containing gas through thewellbore. Referring to FIG. 25 , gas-recovery activity at the wellhead18 is illustrated during the third stage of the timeline of FIG. 21 ,i.e., between Time=T₁ and Time=T₂. As indicated by directional arrow202, natural gas 5 is recovered through the wellbore 10 from thereservoir 35, including from the hydraulic fractures 32, and processedby gas recovery equipment 80 which is in fluid communication with thewellbore 10 at the wellhead 18.

During the third stage of activity, natural gas 5 is produced, i.e.,recovered, at a flow rate that reaches, within a relatively short time,e.g., one month or less of post-hydraulic fracturing clean-up, a maximumflow rate FLOW_(MAX), and the flow rate thereafter declines. The flowrate then undergoes a ‘short-term decline’ that, in various examples,can be fit to a stretched exponential decay curve, a hyperbolic decaycurve, or other decay curve, as shown in FIG. 26 . The ‘short-termdecline’ can take place, if not interrupted, over a period of 12 to 24months, or over a period of 12 to 36 months, or over a period of 12 to48 months, or over a period of 12 to 60 months, or over a period of 24to 36 months, or over a period of 24 to 48 months, or over a period of24 to 60 months, or over a period of 36 to 48 months, or over a periodof 36 to 60 months, or over a period of 36 to 48 months, or over aperiod of 36 to 60 months, or over a period of 48 to 60 months, or overa period of more than 60 months. Following the short-term declineaccording to one of the decline-curve types, ‘long-term decline’ of gasflow rate continues in a manner that can, in some examples, be fit to anexponential tail of any one of the curves. The ‘long-term decline’ cantake place, if not interrupted, over a period of 10 to 20 years, or overa period of 10 to 30 years, or over a period of 20 to 30 years, orlonger. The stages of decline are explained, inter alia, by thestructure and makeup of the hydraulically-fractured well and the variousmechanisms by which natural gas is released from low-permeability shaleformations.

According to Step S102, the gas recovery is characterized by a maximumflow rate FLOW_(MAX). The output process of gas flow can be described bya combination of mechanisms acting at different scales. In an initialperiod of gas recovery, the flow rate reaches maximum flow rateFLOW_(MAX) and proceeds through the period of ‘short-term decline’. Thefirst mechanism is a flow of free (non-adsorbed and non-dissolved) gasmolecules from pores and cracks in the shale formation. Afterequilibrium is disturbed, for example, by the hydraulic fracturing, thefree gas molecules start flowing toward lower pressure, and arerecovered through the wellbore. This flow is called viscous flow, or‘Darcy flow’, because the flow through the porous medium follows Darcy'sLaw which states that flow of a gas through a porous medium has a linearrelationship with both permeability and pressure differential, or, for agiven permeability, flow is proportional to pressure differential.

We refer now to FIG. 27A, a schematic representation, in cross section,of a relatively large pore, e.g., a meso-micropore, in theunconventional gas reservoir. The Darcy flow regime is represented inthe figure by the free-gas velocity profile. Additional gas flow (andrecovery) during the ‘short-term decline’ period occurs by desorption ofmethane from kerogen and clay surfaces, and subsequent flow of the gasmolecules under a pressure gradient. Areas of surface diffusion andabsorption/desorption are marked in FIG. 27A. The longer, residualperiod of ‘long-term decline’ is characterized by gas recoveredsubstantially by diffusion, e.g., Knudsen diffusion, and slip flow insmaller pores, e.g., nanopores. The phrase ‘substantially Knudsendiffusion’ means that at least 50% of the gas recovered is from Knudsendiffusion, or at least 60%, or at least 70%, or at least 80%, or atleast 90%, or at least 95%. FIG. 27B illustrates Knudsen diffusion in ananopore, where the mean pore diameter is smaller than the mean freepath of the gas particles. FIG. 27B also illustrates the diffusion ofsolubilized methane through the pore due to concentration gradient.Knudsen-diffusion, and, to a lesser extent, other diffusion processes,becoming a predominant factor in the flow of recovered gas can be,according to embodiments, associated with a trigger criterion at Time=T₂for beginning injection of hydrogen into the partially-depletedreservoir for long-term and/or short-term storage. In such embodiments,a trigger criterion can be selected as an indicator of the reservoirentering the long-term decline phase associated with gas flow dominatedby diffusion processes.

Like the flow rate, the wellhead pressure is at its maximum at or near,e.g., shortly after, the beginning of production, and declines togetherwith the flow rate, for example, exponentially or hyperbolically. In afield example, maximum flowing wellhead pressure PRESSURE_(MAX) is 6,500PSI (pounds per square inch) at the early production peak, but theflowing wellhead pressure declines to 2,175 psi after one year, and 725psi after 1.5 years.

Step S103

Step S103 includes monitoring a current flow rate FLOW_(CURRENT) of therecovered methane-containing gas 5 over time, and takes place during thethird stage (of the timeline of FIG. 21 ), e.g., alongside Step S102.FIG. 28 shows exponential decay curves for exemplary unconventional gaswells, e.g., wells producing natural gas from the reservoir 35 of FIG.25 . The y-axis of the graph represents current production,FLOW_(CURRENT), as a percentage of the maximum gas recovery rate ofFLOW_(MAX). FLOW_(CURRENT) is shown by each of the decay curves as afunction of time, where time is represented schematically by the x-axiswithout units or scale. According to the method, the monitoring is,inter alia, for detecting that FLOW_(CURRENT) becomes equal to or lessthan a flow-rate trigger criterion FLOW_(TRIGGER). In embodiments,FLOW_(TRIGGER) is set as being equal to at least 10% of FLOW_(MAX) andnot more than 15% of FLOW_(MAX). In some embodiments, FLOW_(TRIGGER) isset as being equal to at least 10% of FLOW_(MAX) and not more than 20%of FLOW_(MAX). In other embodiments, FLOW_(TRIGGER) is set as beingequal to at least 15% of FLOW_(MAX) and not more than 20% of FLOW_(MAX).

The monitoring can include direct flow measurements, and/or can includecalculations based on measurements. The measurements, and calculationsbased on measurements, can include, for example and not exhaustively:measuring instantaneous flow rate and/or cumulative production over aperiod of time such as an hour, a day, or a shorter period or a longerperiod—monitoring the actual gas production rate is straightforward andis regularly accomplished in the industry with high precision;determining the composition of the gas being recovered; determining anisotope ratio such as a ¹²C/¹³C ratio of the methane recovered; and/ordetermining a fluid-flow regime in the reservoir, e.g., a dominantfluid-flow regime, such as viscous flow, desorption, surface diffusion,Knudsen diffusion, or dissolution, wherein the determining thefluid-flow regime can include determining that the dominant flow regimeis Knudsen diffusion. Determining that the dominant flow regime isKnudsen diffusion can be on the basis of an isotope ratio such as a¹²C/¹³C ratio. In an example, ¹²C/¹³C ratio can be tracked to calculatethe prevalence of adsorbed methane (after pore space methane issubstantially used up, i.e., recovered) and the subsequent depletion ofadsorbed methane from the reservoir. As the adsorbed methane isdesorbed, at first the isotopically lighter ¹²C methane is released;after ¹²C methane is substantially depleted, the isotopically heavier¹³C is preferentially desorbed, which is detectable by tracking theisotope ratio. In another example, the determining the fluid-flow regimecan include determining that the dominant flow regime is desorption,e.g., at a point where kerogen has desorbed at least half the methaneadsorption sites.

In some embodiments, a FLOW_(TRIGGER) flow-rate trigger criterion isselected on an ad hoc basis. In an embodiment, FLOW_(TRIGGER) isselected ad hoc on the basis of at least one measurement or at least onecalculation based on a measurement. In a first use-case example,FLOW_(TRIGGER) is reset ad hoc based at least in part on a change inflow rate, a change in a rate of change of flow rate, a change in a rateof change of an isotope ratio or a change in any other relevantparameter. According to the first use-case example, a tentativeFLOW_(TRIGGER) value of 10% of FLOW_(MAX) had been selected andsubsequently reset to 11% based on the monitoring. In a second use-caseexample, FLOW_(TRIGGER) is selected ad hoc because it had not beenpreviously set, and it is set on the basis of the actual decay curvederived from the monitoring data.

In some embodiments, a FLOW_(TRIGGER) flow-rate trigger criterion ispre-selected, e.g., when selecting the reservoir in the first stage(Time<T₀), or when initiating gas recovery (at Time=T₁) or afterproduction reaches maximum flow rate FLOW_(MAX) and begins theexponential decline. In a third use-case example, the flow-rate triggercriterion is selected on the basis of the kerogen concentration in thegeological formation and/or based on a permeability parameter of thegeological formation. According to the non-limiting example. the kerogenconcentration and permeability parameters are used to model, e.g.,predict, a flow velocity for the Darcy flow during the ‘short-termdecline’ represented by an exponential decay curve. In some embodiments,the selection of the reservoir includes selecting the reservoir on thebasis of kerogen concentration in the geological formation. For thepurposes of the present disclosure, the term ‘kerogen-rich’ refers to akerogen concentration of at least 1% organic content by volume, or atleast 2%, or at least 3%, or at least 4%, or at least 5%. Kerogenconcentration may be determined on cuttings or core material using thearea under the S2 peak of a Rock-Eval analysis, or, in well logging,from the difference between the neutron and density porosities afteraccounting for the kerogen density and hydrogen index (HI) of clays, orusing a pulsed-neutron spectroscopy logging tool. Kerogen concentrationmay also be determined from an equation based on total organic carbon(TOC). The adsorption on kerogen may be determined by integration ofpetrophysical analysis from lab and well logging data with N₂, CH₄, andH₂ adsorption isotherms.

Step S104

Step S104 includes injecting a hydrogen gas 8 through the wellbore 10into the geological formation 30, during the fourth stage of thetimeline, between Time=T₂ and Time=T₃. As shown in the example of FIG.29 , where injection of the hydrogen 8 is represented schematically bythe directional arrow 203, hydrogen-gas-pumping arrangements 90 areprovided in fluid communication with the reservoir 35 via wellbore 10.In embodiments, the reservoir 35 and wellbore 10 are the same reservoir35 and wellbore 10 as in FIGS. 23 and 25 .

The skilled artisan will understand that the transition from the thirdstage of recovering methane to the fourth stage of injecting hydrogen atTime=T₂ can involve one or more preparatory steps performed betweenSteps S103 and S104 of the method. For example, it can be desirable toclose valves at the surface to cause pressure in the reservoir 35 toreach an equilibrium pressure. This can include closing the valves atthe surface to end gas recovery upon detecting the FLOW_(TRIGGER)flow-rate trigger criterion, and allowing time for the wellhead pressureto increase from a flowing wellhead pressure to a shut-in wellheadpressure. Over a period of weeks the shut-in wellhead pressure rises toan equilibrium pressure that is approximately equal to reservoirpressure.

The injection of the hydrogen gas 8, e.g., pure H₂, or ahydrogen-containing gas that includes at least 99% H₂ or at least 98%H₂, or at least 97% H₂, or at least 96% H₂, or at least 95% H₂, is at apressure higher than the current gas pressure at the wellhead 18, e.g.,the shut-in wellhead pressure at a stabilized reservoir-equilibriumpressure, so as to ensure that the hydrogen gas 8 propagates throughoutthe well, i.e., including the hydraulic fractures 32 and natural cracks.In some embodiments, the injection of hydrogen gas is at a pressure thatis at least 100 PSI higher than the current shut-in gas pressure at thewellbore 10 or at least 200 PSI higher, or at least 300 PSI higher, orat least 400 PSI higher, or at least 500 psi higher, or at least 800 PSIhigher. In embodiments, the initial injecting of the hydrogen gas 8 isat a pressure below the maximum gas-recovery pressure PRESSURE_(MAX), or50 or more PSI lower than PRESSURE_(MAX) or 100 or more PSI lower thanPRESSURE_(MAX) or 200 or more PSI lower than PRESSURE_(MAX). Inembodiments, the initial injecting of the hydrogen gas 8 is at apressure below a hydrogen fracture extension pressure H₂FRAC_(EXT) atwhich the injection of the hydrogen gas 8 would cause extension of theexisting fractures, including those propagated during the hydraulicfracturing of Step S101. The hydrogen fracture extension pressureH₂FRAC_(EXT) is different than the FRAC_(EXT) with fracturing fluiddiscussed in Step S101 because of the weight of the hydraulic column andthe fluid friction. In some embodiments, H₂FRAC_(EXT) can be computedfrom FRAC_(EXT), e.g., to act as a pressure limit during hydrogeninjection. In other embodiments, H₂FRAC_(EXT) can be measured using adiagnostic fracture injection test (DFIT), or it can be measured bymicroseismic monitoring.

The injection of the hydrogen gas of Step 04 is initiated responsivelyto—and contingent upon—a determination, based on the monitoring or StepS103, that the monitored FLOW_(CURRENT) is equal to or less than theflow-rate trigger criterion FLOW_(TRIGGER). The relationship between thedeclining FLOW_(CURRENT) and a range of values for FLOW_(TRIGGER) isillustrated in the graph of FIG. 28 . FLOW_(CURRENT) declines, forexample, according to any one of the various exemplaryexponential-decline curves of FIG. 28 , until it reaches the flow-ratetrigger criterion FLOW_(TRIGGER). FIG. 28 shows a range of possibleselected values of FLOW_(TRIGGER) from 10% to 20%, and other ranges arepossible. In some embodiments, the flow-rate trigger criterionFLOW_(TRIGGER) is a single value, i.e., of the percentage of FLOW_(MAX),and in other embodiments FLOW_(TRIGGER) is a range of values that aresuitable for triggering the injection of hydrogen 8 into thepartially-depleted reservoir 35.

In embodiments, the injection of hydrogen gas 8 is at a pressure that isnot higher than the hydrogen-injection fracture extension pressureH₂FRAC_(EXT). Inter alia, this limitation is useful for avoiding, atleast partly, damage outside the wellbore 10 and the extension andbroadening of the existing hydraulic fractures 32, for example toprevent the release of additional free methane in and from the newlyexpanded fractures which affects the hydrogen purity during hydrogenproduction, and to prevent hydrogen loss to the formation. In someembodiments, the injecting of the hydrogen gas 8 is at a pressure thatis at least 200 PSI or at least 500 PSI less than H₂FRAC_(EXT). In someembodiments, the initial injecting of the hydrogen gas 8 is at apressure just below H₂FRAC_(EXT). In an example, the injecting of thehydrogen gas includes injecting the hydrogen gas at a pressure that is100 PSI less than H₂FRAC_(EXT). In some embodiments, surface geophysicalmonitoring, i.e., geophysical monitoring of the geological structurefrom the surface, is performed during hydrogen injection to determinewhether or not hydraulic fractures 32 are being extended by the hydrogeninjection. According to non-limiting examples, surface geophysicalmonitoring can include the use of surface geophysical monitoringequipment 95 such as microseismic arrays or tiltmeters. Gas phasetracers may also be added to the injected hydrogen 8 to see whetherthere is any communication of the hydrogen with adjacent productionwells on the wellhead. Suitable gas phase tracers are tritiated hydrogensuch as HT or T₂ in the range of 3 to 30×10{circumflex over ( )}10Becquerel (Bq) that may be detected at extremely low concentrations innearby production wells. According to a non-limiting example, atracer-gas facility 96 for adding a gas-phase tracer to the injectedhydrogen gas 8 is provided at or near the wellhead 10.

Step S105

Step S105 includes recovering stored hydrogen gas 8 through the wellbore10, during the fifth stage of the timeline, between Time=T₃ and Time=T₄.As shown in the example of FIG. 30 , where recovery of thehydrogen-containing gas 8 is represented schematically by thedirectional arrow 204, hydrogen-gas-recovery equipment 80 is provided influid communication with the reservoir 35 via wellbore 10. Inembodiments, the reservoir 35 and wellbore 10 are the same reservoir 35and wellbore 10 as in FIGS. 23, 25 and 29 . The recoveredhydrogen-containing gas 8 can include, as illustrated schematically inFIG. 31 , bulk-phase H₂ in hydraulic fractures, H₂ in kerogen porespaces, H₂ adsorbed on kerogen surfaces, H₂ dissolved in kerogen, and/orbulk-phase H₂ contained in the non-organic pores or adsorbed on clays ofthe matrix of the geological formation 30.

According to the method, the recovered hydrogen-containing gas 8 has anH₂ molar fraction of at least 85%. The H₂ molar fraction of therecovered gas can be directly impacted by the selection of the reservoirin the first stage, e.g., selection of a kerogen-rich reservoir, and/orselection of a kerogen-rich reservoir with low permeability, as theterms have been defined herein. The H₂ molar fraction of the recoveredgas can be directly impacted by the selection of a flow-rate triggercriterion FLOW_(TRIGGER) with respect to the current flow rateFLOW_(CURRENT) of natural gas for initiating the injection of hydrogengas into the reservoir to begin the fourth stage. In embodiments,FLOW_(TRIGGER) is chosen to correspond to a state of the reservoir inwhich pore methane and kerogen-adsorbed methane is largely alreadyrecovered, such that the hydrogen gas replaces the methane in thefaster-recovery locations of the shale formation. The proper selectionof a FLOW_(TRIGGER) in terms of the timing of the initiating can lead toavoiding significant contamination of the H₂ by CH₄ in the pore spacesor desorbed from kerogen surfaces, and thus the recovered hydrogen canbe of higher purity, where purity refers to the H₂ molar fraction of therecovered gas. In various examples, the purity is at least 85%, or atleast 86%, or at least 87%, or at least 88%, or at least 89%, or atleast 90%, or at least 91%, or at least 92%, or at least 93%, or atleast 94%, or at least 95%, or at least 96%, or at least 97%, or atleast 98%, or at least 99%. In embodiments, the remainder of the gas,i.e., after subtracting the H₂ molar fraction, is at least predominantlyCH₄.

In some embodiments, not all the steps S101, S102, S103, S104, S105 ofthe method are performed.

We now refer to FIG. 31 . The chart in FIG. 31 schematically illustrateschanges in gas pressure in the hydraulically fractured reservoir 35 overtime, specifically during the third, fourth and fifth stages asdescribed hereinabove, corresponding to Steps S102, S104 and S105,respectively, of the foregoing method. As seen in the portion of thechart related to the third stage and before Time=T₂, reservoir pressurepeaks quickly at the maximum pressure PRESSURE_(MAX) and declines, e.g.,exponentially, or in some examples hyperbolically, to the minimumpressure PRESSURE_(MIN) at Time=T₂. In other words, the minimum pressurePRESSURE_(MIN) of FIG. 31 occurs at the same time as the flow-ratetrigger criterion FLOW_(TRIGGER) of FIG. 28 . Once H₂ injection (fourthstage) is initiated at Time=T₂, reservoir pressure rises until thereservoir pressure approaches PRESSURE_(MAX), e.g., within 100 PSI ofPRESSURE_(MAX), or within 50 PSI of PRESSURE_(MAX), at Time=T₃. AfterTime=T₃, recovery of hydrogen can commence (fifth stage), and again thepressure falls exponentially, or in some examples, hyperbolically. Insome embodiments, the H₂ injection of the fourth stage, e.g., of StepS104, proceeds more rapidly than the gas-recovery phase of the thirdstage, e.g., of Step S102, such that the fourth stage lasts one-half orone-third or some other fraction (<1) of the time of the third stage. Insome embodiments, the H₂ recovery of the fifth stage, e.g., of StepS105, can proceed more rapidly than the gas-recovery phase of the thirdstage, e.g., of Step S102, such that the fifth stage lasts one-half orone-third or some other fraction (<1) of the length of time of the thirdstage. Thus, the decline in pressure in the H₂-recovery phase of thefifth stage is faster, e.g., twice as fast or three times as fast, thanin the natural-gas-recovery phase of the third stage, because of thelower viscosity and higher diffusivity of H₂ gas compared to CH₄ gas.

Referring again to FIGS. 29 and 30 , a system 200 for storing andsubsequently recovering a hydrogen-containing gas 8 comprises pumpingarrangements 80 for the hydrogen-containing gas 8. The pumpingarrangements 80 are in fluid communication with the wellbore 10 and areconfigured to inject hydrogen gas 8 therethrough into thehydraulically-fractured reservoir 35. In some embodiments, kerogenconcentration in the reservoir is at least 1% by volume, or at least 2%,or at least 3%. The pumping arrangements 80 include pumps andcompressors, piping (e.g., piping 12), power equipment, and otherequipment as necessary for injecting the hydrogen gas 8. The pumpingarrangements 80 are configured to inject the hydrogen 8 at a pressurehigher than a current shut-in gas pressure at the wellbore. According toembodiments, the reservoir 35 is partially depleted by amethane-containing-gas recovery process.

The gas-recovery process of the reservoir 35 is characterized, asillustrated schematically in FIG. 32 , by a stretched exponential, or insome embodiments, hyperbolic, decline in gas recovery rate from a peakflow rate of FLOW_(MAX) to a minimum flow rate of FLOW_(MIN) which atleast 10% of FLOW_(MAX) and not more than 15% of FLOW_(MAX). Inembodiments, FLOW_(MIN) is at least 10% of FLOW_(MAX) and not more than20% of FLOW_(MAX). In other embodiments, FLOW_(MIN) is at least 15% ofFLOW_(MAX) and not more than 20% of FLOW_(MAX). In some embodiments, thefluid flow regime of the reservoir is substantially diffusional. Thephrase ‘substantially diffusional’ means that at least 50% of the gasrecovered at the end of the gas recovery process was from diffusion. orat least 60%, or at least 70%, or at least 80%, or at least 90%, or atleast 95%. In various examples, the diffusion includes Knudsen, surfaceand/or solution diffusion.

The system 200 additionally comprises gas-recovery equipment 80, also influid communication with the reservoir 35 though the wellbore 10. Thegas-recovery equipment 80 is operative to recover a portion of thestored hydrogen-containing gas 8 through the wellbore 10. The system isoperable such that the recovered portion of the hydrogen-containing gas8 has an H₂ molar fraction of at least 85%. In various examples, the H₂molar fraction is at least 85%, or at least 86%, or at least 87%, or atleast 88%, or at least 89%, or at least 90%, or at least 91%, or atleast 92%, or at least 93%, or at least 94%, or at least 95%, or atleast 96%, or at least 97%, or at least 98%, or at least 99%. Inembodiments, the remainder of the gas, i.e., after subtracting the H₂molar fraction, is at least predominantly CH₄.

In some embodiments, the pumping arrangements 80 are operative to injectthe hydrogen-containing gas 8 at a pressure that is at least 500 PSIhigher than the current shut-in gas pressure at the wellbore 10. In someembodiments, the pumping arrangements 90 are operative to inject thehydrogen-containing gas 8 at a pressure that is no more than 100 PSIless than a maximum wellhead pressure of the gas-recovery process of thereservoir 35, PRESSURE_(MAX). In some embodiments, the pumpingarrangements 90 are operative to inject the hydrogen-containing gas 8 ata pressure that is no more than 50 PSI less than PRESSURE_(MAX).

In some embodiments, the system 200 additionally includes surfacegeophysical-monitoring equipment for determining whether hydraulicfractures, e.g., one or more hydraulic fractures, are being extended bythe hydrogen injection. Suitable examples of surfacegeophysical-monitoring equipment include microseismic arrays andtiltmeters.

Referring now to FIG. 33 , a method is disclosed for storing andsubsequently recovering a hydrogen gas. As illustrated by the flowchartin FIG. 33 , the method comprises Steps S111 and S112, which arediscussed in the following paragraphs. A suitable system for use inperforming the method is the system 200 described above in connectionwith FIGS. 29 and 30 .

Step S111

Step S111 includes injecting hydrogen gas 8 through a horizontalwellbore 10 into a hydraulically-fractured, kerogen-rich, andpartially-depleted reservoir of a methane-containing gas 3, at apressure higher than a current shut-in gas pressure at the wellhead 10.For the purposes of the present disclosure, the term ‘kerogen-rich’refers to a kerogen concentration of at least 1% organic content byvolume, or at least 2%, or at least 3% The partial depletion of thepartially-depleted reservoir is by a methane-containing-gas recoveryprocess that is characterized, e.g., as illustrated in FIG. 33 , by amaximum flow rate of FLOW_(MAX), and a minimum flow rate of FLOW_(MIN)that is at least 10% of FLOW_(MAX) and not more than 15% of FLOW_(MAX).In embodiments, FLOW_(MIN) is at least 10% of FLOW_(MAX) and not morethan 20% of FLOW_(MAX). In other embodiments, FLOW_(MIN) is at least 15%of FLOW_(MAX) and not more than 20% of FLOW_(MAX).

In some embodiments, the methane-containing-gas recovery process isadditionally characterized by a maximum wellhead pressure ofPRESSURE_(MAX), and the injecting of the hydrogen gas 8 of Step S111includes injecting the hydrogen gas 8 at a pressure that is 100 or morePSI less than PRESSURE_(MAX), i.e., at most (PRESSURE_(MAX)−100 PSI). Inembodiments, the injecting of the hydrogen gas 8 includes injecting thehydrogen gas 8 at a pressure that is at least 500 PSI higher than thecurrent shut-in gas pressure at the wellhead 10.

In some embodiments, the injecting of the hydrogen gas 8 is at apressure that is at least 200 PSI or at least 500 PSI less than thehydrogen fracture extension pressure H₂FRAC_(EXT). In some embodiments,the initial injecting of the hydrogen gas 8 is at a pressure just belowthe hydrogen fracture extension pressure H₂FRAC_(EXT). In someembodiments, surface geophysical monitoring, i.e., geophysicalmonitoring of the geological structure 30 from the surface, is performedduring hydrogen injection to determine whether or not hydraulicfractures 32 are being extended by the hydrogen injection. According tonon-limiting examples, surface geophysical monitoring can include theuse of surface geophysical monitoring equipment 95 such as microseismicarrays or tiltmeters. According to a non-limiting example, a tracer-gasfacility 96 for adding a gas-phase tracer to the injected hydrogen gas 8is provided at or near the wellhead 10.

Step S112

Step S112 includes recovering a portion of the stored hydrogen gas 8through the wellbore 10. The recovered hydrogen gas is mostly purehydrogen, i.e., has an H₂ molar fraction of at least 85%, or at least86%, or at least 87%, or at least 88%, or at least 89%, or at least 90%,or at least 91%, or at least 92%, or at least 93%, or at least 94%, orat least 95%, or at least 96%, or at least 97%, or at least 98%, or atleast 99%. The remainder of the recovered gas mix can include methaneand other hydrocarbon gases such as ethane and propane, andnon-hydrocarbon gases such as carbon dioxide and nitrogen.

Referring now to FIG. 34 , a method is disclosed for storing andsubsequently recovering a hydrogen gas. As illustrated by the flowchartin FIG. 34 , the method comprises Steps S121, S111 and S112. Steps S111and S112 have been discussed hereinabove, and Step S121 is discussed inthe following paragraph. A suitable system for use in performing themethod is the system 200 described above in connection with FIGS. 29 and30 .

Step S121

Step S121 includes selecting the unconventional gas reservoir 35 basedon a kerogen concentration in the reservoir 35. Examples of suitablekerogen concentration levels include at least 1% organic content byvolume, or at least 2%, or at least 3%.

Referring now to FIG. 35 , a method is disclosed for storing andsubsequently recovering a hydrogen gas. As illustrated by the flowchartin FIG. 35 , the method comprises Steps S131, S111 and S112. Steps S111and S112 have been discussed hereinabove, and Step S131 is discussed inthe following paragraph. A suitable system for use in performing themethod is the system 200 described above in connection with FIGS. 29 and30 .

Step S131

Step S131 includes selecting the unconventional gas reservoir 35 basedon a fluid-flow regime of the reservoir 35. An example of a suitablefluid-flow regime is a substantially Knudsen-diffusion fluid-flowregime. The phrase ‘substantially diffusional’ means that at least 50%of the gas recovered at the end of the gas recovery process was fromdiffusion. or at least 60%, or at least 70%, or at least 80%, or atleast 90%, or at least 95%. In various examples, the diffusion includesKnudsen, surface and/or solution diffusion.

According to still further embodiments of the invention, anunconventional gas reservoir can be suitable for long-term and/orshort-term storage of hydrogen gas after partial depletion of thenatural gas. The timeline of FIG. 36 shows a sequence of stagesassociated with the use of a partially-depleted unconventional gasreservoir for storage and recovery of hydrogen in accordance withembodiments. In a first stage, before Time=T₀, a suitable gas-containingreservoir is selected, e.g., based on one or more technical and/oreconomic selection criteria, and a deep horizontal wellbore isestablished in the reservoir. Non-limiting examples of technicalselection criteria include, and not exhaustively: low permeability,e.g., permeability lower than 10⁻¹ millidarcy (mD), lower than 10⁻² mD,lower than 10⁻³ mD, or lower than 10⁻⁴ mD; proportion of solid organicmatter (i.e., kerogen), e.g., at least 1% kerogen, at least 2% kerogen,or at least 3% kerogen; and distribution of pore volumes in the kerogen.

In a second stage, between Time=T₀ and Time=T₁, the reservoir ishydraulically fractured. The deep horizontal wellbore is perforated forhydraulic fracturing, e.g., by a perforating gun. A fracturing fluid isinjected under pressure through a horizontal wellbore into thegeological formation to cause the fracturing by propagation andexpansion of cracks in the rock structure. The hydraulic fracturingprocess is used to facilitate and/or accelerate the recovery of gas fromthe reservoir by opening up cracks in the deep shale formations. As isknown in the art, successive sections of the reservoir along thewellbore are fractured sequentially and not simultaneously. An exampleof a suitable fracturing fluid is a mixture of water, a proppant such assand or a ceramic, and/or a chemical or polymer to improve a flowcharacteristic such as the water's surface friction and/or to act as alubricant. In other examples, a suitable fracturing fluid can include anenergized fluid, e.g., a fluid including at least one compressed orcompressible gas-phase material, or an oil-based fluid.

In a third stage, between Time=T₁ and Time=T₂, natural gas is recoveredfrom the hydraulically-fractured reservoir. The gas recovery processover time is characterized by one or more isotope ratios that changeover time, as will be further described hereinbelow.

In a fourth stage, between Time=T₂ and Time=T₃, hydrogen gas is injectedinto the reservoir. In embodiments, the transition from the third stageto the fourth stage, at Time=T₂, is based on a trigger criterion. Thetrigger criterion can include a trigger criterion that corresponds to achange in an isotope ratio matching an isotope-signature triggercriterion. An example of an isotopic-signature trigger criterionsuitable for triggering a transition of operation of an unconventionalgas reservoir to injecting compressed hydrogen for long- and/orshort-term storage is a δ(¹³C) isotopic signature based on a ratio of¹³C to ¹²C (or vice versa). In a first exemplary implementation, theδ(¹³C) isotopic signature of a specific hydrocarbon in the gas recoveredfrom the reservoir, such as methane, ethane, propane, butane, or pentaneis monitored with respect to the isotopic-signature trigger criterion.In a second exemplary implementation, the δ(¹³C) isotopic signature of amix of one or more, or all, hydrocarbons in the gas recovered from thereservoir is monitored with respect to the isotopic-signature triggercriterion.

Another example of a suitable isotopic-signature trigger criterion fortriggering a transition to hydrogen injection includes aδ(C_(X)H_(Y-1)D/C_(X)H_(Y)) isotopic signature, which represents a ratioof deuterated hydrocarbon molecules to non-deuterated molecules where Xand Y are the number of carbon and hydrogen atoms, respectfully. Thisexpression (and similar expressions throughout the present disclosure),which include a single deuteron in the numerator, is used forconvenience and is not intended to imply that all deuterated hydrocarbonmolecules detected are specifically monodeuterated molecules. A smalland typically insignificant number of molecules are not monodeuterated,i.e., have multiple deuteron atoms in a molecule, and such molecules areincluded in any analysis of monitored isotope signatures. Examples ofsuitable hydrocarbons having the form C_(X)H_(Y) include members of themonodeuterated C1-C5 alkane group consisting of: methane, ethane,propane, butane and pentane, and a δ(C_(X)H_(Y-1)D/C_(X)H_(Y)) isotopicsignature can refer to any one of such hydrocarbons having the formC_(X)H_(Y).

Further examples of suitable isotopic-signature trigger criteria fortriggering a transition to hydrogen injection include isotopicsignatures having the generalized form δ(EXP₁/EXP₂), where:

-   -   In a first further example, EXP₁ is an expression representing a        monodeuterated multi-alkane sum of respective concentrations of        one or more of: monodeuterated ethane, monodeuterated propane,        monodeuterated butane, and monodeuterated pentane, and EXP₂ is        an expression representing a concentration of monodeuterated        methane.    -   In a second further example, EXP₁ is an expression representing        a monodeuterated-methane concentration, and EXP₂ is an        expression representing a respective concentration of any one        of: monodeuterated ethane, monodeuterated propane,        monodeuterated butane, and monodeuterated pentane.    -   In a third further example, EXP₁ is an expression representing        respective concentrations of one or more members of the        monodeuterated C1-C5 alkane group consisting of monodeuterated        methane, monodeuterated ethane, monodeuterated propane,        monodeuterated butane, and monodeuterated pentane, and EXP₂ is        an expression representing respective concentrations of one or        more members of the same monodeuterated C1-C5 alkane group with        the exception of the one or more members represented in EXP₁.    -   In a fourth further example, EXP₁ is an expression representing        any member of the same monodeuterated C1-C5 alkane group, and        EXP₂ is an expression representing any other member of the same        monodeuterated C1-C5 alkane group.

Still further examples of suitable isotopic-signature trigger criteriafor triggering a transition to hydrogen injection include isotopicsignatures having the form a δ(C_(X)H_(Y-1)D/C_(A)H_(B)), whereC_(X)H_(Y-1)D is a monodeuterated molecule of a first hydrocarbon, andC_(A)H_(B) is a non-deuterated molecule of a second hydrocarbon that isnot the first hydrocarbon. It will be clear to the skilled artisan thatany of the foregoing ratios can be expressed in other ways, for exampleby reversing numerators and denominators of any ratio, i.e., flippingover the ratios such that where an isotopic-signature value based on anyof the foregoing ratios might increase based on physical analysis, sucha value would instead decrease, and vice versa.

In a fifth stage, between Time=T₃ and Time=T₄, stored hydrogen gas isrecovered from the reservoir. The recovered hydrogen gas is mostly purehydrogen, i.e., has an H₂ molar fraction of at least 85%, or at least86%, or at least 87%, or at least 88%, or at least 89%, or at least 90%,or at least 91%, or at least 92%, or at least 93%, or at least 94%, orat least 95%, or at least 96%, or at least 97%, or at least 98%, or atleast 99%. The remainder of the recovered gas mix can include methane,other hydrocarbon gases such as ethane and propane, and non-hydrocarbongases such as carbon dioxide and nitrogen.

In a sixth stage, after Time=T₄, the injecting and recovering ofhydrogen can be cycled. The sixth stage can thus be considered arepetition or cycling of the fourth and fifth stages. In someembodiments, when the hydrogen recovery of the fifth stage reaches ahydrogen-production trigger criterion, operation of the reservoirreverts to injecting hydrogen, inter alia to increase pressure andimprove future hydrogen recovery volume. In some embodiments, hydrogenis cycled on a daily basis, meaning that within a single diurnal cycle,hydrogen is injected, and then recovered. The diurnal cycle can repeatindefinitely. In some such embodiments, the fourth-stage injection ofhydrogen can be up to a ‘base level’, on top of which there is a dailycycle of fluctuation, so that the daily recovery cycle is at asufficiently high pressure to ensure rapid recovery. In otherembodiments, the cycle of injecting hydrogen and subsequently recoveringa hydrogen-containing gas can take place over weeks, months or years.

Any or all of the times T₀, T₁, T₂, T₃ and T₄ can be points in time orperiods of time, for example, days, weeks or months.

Referring now to FIG. 37 , a method is disclosed for storing hydrogengas in a kerogen-rich geological formation. As illustrated by theflowchart in FIG. 37 , the method comprises Steps S201, S202, S203, S204and S205, which are discussed in the following paragraphs.

Step S201

Step S201 includes injecting a fracturing fluid through a horizontalwellbore into the geological formation to cause fracturing within thegeological formation. Arrangements for injecting a fracturing fluid intoa geological formation are illustrated schematically in FIG. 38 . Ageological formation 30, shown in accordance with the descriptionhereinabove of the second stage between Time=T₀ and Time=T₁, includes anorganic-rich shale deposit (also called a shale formation). Hydraulicfracturing equipment 70 is disposed at a wellhead 18. The wellhead 18 islocated at a well pad 19 and is in fluid communication with anunconventional gas reservoir 35 located within the shale formation 30,which in the non-limiting example of FIG. 38 is below the water table27.

The wellbore 10, including perforated casing, is horizontally-orientedat the depth of the shale formation 30, and can extend horizontally fortens, hundreds or thousands of meters. As indicated by the directionalarrow 201, a hydraulic-fracturing fluid 3 is injected into (and through)the wellbore 10 and thence into fractures 32. The injecting is effectiveto increase pressure at the target depth of the reservoir 35, e.g.,based on the depth of the wellbore, to exceed that of the fracturegradient of the rock. At a fracture-initiating pressure known as a‘breakdown pressure’, the deep rock surrounding the wellbore 10 crackswith pressure. Once fracturing is initiated, pressure at the wellhead 18drops and then starts increasing, as the fracturing fluid 3 permeatesthe rock, further extending the fractures. This occurs at thefracture-extending pressure FRAC_(EXT). Fractures predominantlyperpendicular to the wellbore may reach lengths of a few hundred feetlong; the height of the fractures 32 is controlled by the stresses inthe rock formations above and below the wellbore.

FIG. 38 illustrates only a single well, but a single geologicalformation 30 or a single unconventional gas reservoir 35 can be servicedby multiple wells, as shown in FIG. 39 . FIG. 39 illustrates multiplewells (indicated by wellbores 10) at each well pad 19, and multiple wellpads 19 servicing the gas reservoir 35. In the non-limiting example ofFIG. 39 , gas flows through a network of transmission nodes to a centraltreatment hub that services the multiple wells. The example of FIG. 39shows 8 wells, i.e., wellbores 10, operating from each well pad 19. Inother examples, not illustrated, there can be any number of wells, suchas for example, 16, 32 or 64 wells. Each well comprises a wellhead 18and a wellbore 10. Pressure and flow measurements may be made usingpressure and flow gauges at the wellhead 18 while flowing or duringshut-in. Pressure may also be measured downhole using downhole pressuregauges.

Step S202

Step S202 includes recovering a methane-containing gas 5 through thewellbore. Referring to FIG. 40 , gas-recovery activity at the wellhead18 is illustrated during the third stage of the timeline of FIG. 36 ,i.e., between Time=T₁ and Time=T₂. As indicated by directional arrow202, natural gas 5 is recovered through the wellbore 10 from thereservoir 35, including from the hydraulic fractures 32, and processedby gas recovery equipment 80 which is in fluid communication with thewellbore 10 at the wellhead 18.

Step S203

Step S203 includes monitoring an isotopic signature of a molecularcomponent of the recovered methane-containing gas. According toembodiments, any one (or, in some embodiments: more than one) of severalisotopic signatures can be used to determine a ‘trigger’ criterion forinitiating a transition from recovering the methane-containing gas 5from the reservoir 35 to injecting compressed hydrogen for long- and/orshort-term storage.

In embodiments, the monitoring includes periodically sampling andanalyzing the methane-containing gas 5 produced from the reservoir 35.

First Example

A first example of a suitable isotopic signature for monitoring as atrigger criterion is a δ(¹³C) isotopic signature based on a ratio of ¹³Cto ¹²C (or vice versa) for methane, although isotopic signatures ofother component gases of the recovered natural gas 5, e.g., ethane,propane, butane and pentane, are also suitable.

FIG. 41 is a chart showing an exemplary graph of a δ(¹³C) isotopicsignature for methane over time, i.e., during the third-stagegas-recovery period between Time=T₁ and Time=T₂. FIG. 41 illustratesthat carbon isotope ratio in the methane gas produced from the shale gasreservoir 35 can change over time during the commercial life of theunconventional gas reservoir. According to embodiments, these changescan be monitored in order to detect matching a ‘trigger criterion’ thatcan be used to trigger a transition to injecting hydrogen into thereservoir. Exemplary periodic gas sampling points are indicated in FIG.41 by periodic sampling points 980. The time between sampling points 980is not necessarily constant. As previously discussed, similar δ(¹³C)isotopic signatures can be obtained for ethane, for propane, for butane,and for other hydrocarbon gases produced from the shale gas reservoir.Ratios of ¹³C isotopic signatures respective of the various componentgases of the recovered natural gas 5 may also be obtained, for examplein the form δ(¹³C)_(ALKANE1)/δ(¹³C)_(ALKANE2) where ALKANE1 and ALKANE2are selected from the C1-C5 alkane group consisting of methane, ethane,propane, butane and pentane. Additionally or alternatively, either orboth of the numerator and the denominator can include a δ(¹³C) isotopicsignature expression arithmetically combining multiple members of theC1-C5 alkane group.

As is known in the art, gas is produced, i.e., recovered, from anunconventional gas reservoir from three sources: free gas, desorbed gas,and diffusion of dissolved gas through kerogen. At different timesduring a project, gas from different sources can be the dominantcomponent in gas recovered from the reservoir. For purposes ofillustration, the graph of FIG. 41 indicates three periods correspondingto these three gas sources, for specific periods of time shown in yearson the logarithmic x-axis of the graph. This ‘assignment’ to specificperiods of time reflects a schematically-drawn example of a specifictype of reservoir, and the actual durations of each of the threesuccessive periods varies from reservoir to reservoir, depending on thespecific geologic attributes of each reservoir. In some examples, eachone of the three periods can be longer or shorter than shown in theexample. In some examples, the transition from one such period toanother can start earlier or later, or end earlier or later, than shownin the example. In some examples, there can be transition periods inwhich the dominant component switches back and forth for some period oftime.

The graph of FIG. 41 shows the recovered gas as having a value ofδ(¹³C), e.g., in methane or another component gas of the recovered gas 5such as a different member of the C1-C5 alkane group, that issubstantially constant with time of production during the ‘free-gas’period. This value, δ(¹³C)_(INITIAL), varies among unconventional gasreservoirs and is largely determined by initial geological conditions ofthe specific reservoir. The δ(¹³C) isotopic signature can defined by theratio of ¹³C/¹²C relative to an international standard known as VPDB;δ(¹³C)_(INITIAL) generally varies −20 to −50‰ (VPDB), depending on thegeological age of the reservoir formation, the type of kerogen, and thegeothermal history.

During the monitoring step of S203, a change in isotopic signatureΔδ(¹³C) can be defined by: δ(¹³C)_(INITIAL)−δ(¹³C)_(T) where δ(¹³C)_(T)is the isotopic signature at a later time during the gas recovery periodbetween Time=T₂ and Time=T₃. As can be seen in the graph of FIG. 41 ,δ(¹³C) can undergo substantial changes during the period labeled asdominated by ‘desorbed-gas’ production; in this example, after a periodof 0.5-6 months from the beginning of gas production, δ(¹³C) is shown asdecreasing below the initial ‘free-gas’ period value. In embodiments,δ(¹³C) reaches a minimum value δ(¹³C)_(MIN) during the ‘desorbed-gas’production period. The value of δ(¹³C)_(MIN) can depend on a combinationof factors including the amount of kerogen in the selected reservoir,the reservoir pressure, and the reservoir temperature. Typical values ofΔ(δ¹³C)_(MIN) may be between −1 and −5% c.

According to embodiments, the isotopic signature δ(¹³C) starts to riseafter reaching the minimum value δ(¹³C)_(MIN), and can eventually riseabove the δ(¹³C)_(INITIAL) signature value of the initial free-gasperiod. As shown in FIG. 41 , the value of δ(¹³C)_(T) reaches a maximumvalue δ(¹³C)_(MAX) after at least 2 years of gas recovery, or after atleast 5 years of gas recovery, or after at least 10 years of gasrecovery, or after at least 15 years of gas recovery, and then start todecrease once again. Typical values of Δ(δ¹³C)_(MAX) may be between +1and +15% c.

Second Example

A second example of a suitable isotopic signature for monitoring as atrigger criterion is one that is based on a deuterium-isotope ratio of ahydrocarbon-molecule component found in the methane-containing gas. Fora hydrocarbon molecule given the general formula C_(X)H_(Y) (X carbonatoms and Y hydrogen atoms), the isotope signature to be monitored isδ(C_(X)H_(Y-1)D/C_(X)H_(Y)) based on the isotope ratioC_(X)H_(Y-1)D/C_(X)H_(Y), or, equivalently in terms of suitability,C_(X)H_(Y-1)D/(C_(X)H_(Y)+C_(X)H_(Y-1)D).

A first example of a hydrocarbon-molecule component is methane (CH₄). Asuitable isotope ratio for monitoring as a trigger criterion relates tomonodeuterated methane: CH₃D/CH₄ or, equivalently in terms ofsuitability, CH₃D/(CH₄+CH₃D). As discussed earlier, there can be somemethane molecules with multiple protium atoms substituted by deuteriumatoms, and these are included in the analysis along with themonodeuterated methane molecules.

A second example of a hydrocarbon-molecule component is ethane (C₂H₆). Asuitable isotope ratio for monitoring as a trigger criterion relates tomonodeuterated ethane: C₂H₅D/C₂H₆ or, equivalently in terms ofsuitability, C₂H₅D/(C₂H₆+C₂H₅D). As discussed earlier, there can be someethane molecules with multiple protium atoms substituted by deuteriumatoms and these are included in the analysis along with themonodeuterated ethane molecules.

A third example of a hydrocarbon-molecule component is propane (C₃H₈). Asuitable isotope ratio for monitoring as a trigger criterion relates tomonodeuterated propane: C₃H₇D/C₃H₈ or, equivalently in terms ofsuitability, C₃H₇D/(C₃H₈+C₃H₇D). As discussed earlier, there can be somepropane molecules with multiple protium atoms substituted by deuteriumatoms and these are included in the analysis along with themonodeuterated propane molecules.

A fourth example of a hydrocarbon-molecule component is butane (C₄H₁₀).A suitable isotope ratio for monitoring as a trigger criterion relatesto monodeuterated butane: C₄H₉D/C₄H₁₀ or, equivalently in terms ofsuitability, C₄H₉D/(C₄H₁₀+C₄H₉D). As discussed earlier, there can besome butane molecules with multiple protium atoms substituted bydeuterium atoms and these are included in the analysis along with themonodeuterated butane molecules.

A fifth example of a hydrocarbon-molecule component is pentane (C₅H₁₂).A suitable isotope ratio for monitoring as a trigger criterion relatesto monodeuterated pentane: C₅H₁₁D/C₅H₁₂ or, equivalently in terms ofsuitability, C₅H₁₁D/(C₅H₁₂+C₅H₁₁D). As discussed earlier, there can besome pentane molecules with multiple protium atoms substituted bydeuterium atoms and these are included in the analysis along with themonodeuterated pentane molecules.

Collectively, methane, ethane, propane, butane and pentane are membersof the C1-C5 alkane group, and monodeuterated methane, monodeuteratedethane, monodeuterated propane, monodeuterated butane and monodeuteratedpentane are members of the monodeuterated C1-C5 alkane group

FIG. 42 includes a chart, similar to the chart of FIG. 41 , showing anexemplary graph of a δ(C_(X)H_(Y-1)D/C_(X)H_(Y)) isotopic signature overtime, i.e., during the third-stage gas-recovery period between Time=T₁and Time=T₂. FIG. 42 illustrates that a hydrocarbon-molecule isotoperatio in the methane gas produced from the shale gas reservoir 35 canchange over time during the commercial life of the unconventional gasreservoir. According to embodiments, these changes can be monitored inorder to detect matching a ‘trigger criterion’ that can be used totrigger a transition to injecting hydrogen into the reservoir. Exemplaryperiodic gas sampling points are indicated in FIG. 42 by periodicsampling points 990. The time between sampling points 990 is notnecessarily constant.

The graph of FIG. 42 shows the recovered gas as having a value ofδ(C_(X)H_(Y-1)D/C_(X)H_(Y)) that is substantially constant with time ofproduction during the ‘free-gas’ period. This value,δ(C_(X)H_(Y-1)D/C_(X)H_(Y))_(INITIAL), varies among unconventional gasreservoirs and is largely determined by initial geological conditions ofthe specific reservoir. As can be seen in the graph of FIG. 42 ,δ(C_(X)H_(Y-1)D/C_(X)H_(Y)) can undergo substantial changes during theperiod labeled as dominated by ‘desorbed-gas’ production; in thisexample, after a period of 0.5-6 months from the beginning of gasproduction, δ(C_(X)H_(Y-1)D/C_(X)H_(Y)) is shown as decreasing below theinitial ‘free-gas’ period value. In embodiments,δ(C_(X)H_(Y-1)D/C_(X)H_(Y)) reaches a minimum valueδ(C_(X)H_(Y-1)D/C_(X)H_(Y))_(MIN) during the ‘desorbed-gas’ productionperiod. The value of δ(C_(X)H_(Y-1)D/C_(X)H_(Y))_(MIN) can depend on acombination of factors including the amount of kerogen in the selectedreservoir, the reservoir pressure, and the reservoir temperature.

According to embodiments, the isotopic signatureδ(C_(X)H_(Y-1)D/C_(X)H_(Y)) starts to rise after reaching the minimumvalue δ(C_(X)H_(Y-1)D/C_(X)H_(Y))_(MIN), and can eventually rise abovethe δ(C_(X)H_(Y-1)D/C_(X)H_(Y))_(INITIAL) signature value of the initialfree-gas period. As shown in FIG. 42 , the value ofδ(C_(X)H_(Y-1)D/C_(X)H_(Y))_(T) can reach a maximum valueδ(C_(X)H_(Y-1)D/C_(X)H_(Y))_(MAX) after at least 5 years of gasrecovery, or after at least 10 years of gas recovery, or after at least15 years of gas recovery, and then start to decrease once again.

Step S204

Step S204 includes injecting a hydrogen gas 8 through the wellbore 10into the geological formation 30, i.e., into the reservoir 35, duringthe fourth stage of the timeline, between Time=T₂ and Time=T₃. As shownin the example of FIG. 43 , where injection of the hydrogen 8 isrepresented schematically by the directional arrow 203,hydrogen-gas-pumping arrangements 90 are provided in fluid communicationwith the reservoir 35 via wellbore 10. In embodiments, the reservoir 35and wellbore 10 are the same reservoir 35 and wellbore 10 as in FIGS. 38and 40 .

The skilled artisan will understand that the transition from the thirdstage of recovering methane to the fourth stage of injecting hydrogen atTime=T₂ can involve one or more preparatory steps performed betweenSteps S203 and S204 of the method. For example, it can be desirable toclose valves at the surface to cause pressure in the reservoir 35 toreach an equilibrium pressure. This can include closing the valves atthe surface to end gas recovery and allowing time for the wellheadpressure to increase from a flowing wellhead pressure to a shut-inwellhead pressure. Over a period of weeks, the shut-in wellhead pressurerises to an equilibrium pressure that is approximately equal toreservoir pressure.

The injection of the hydrogen gas 8, e.g., pure H₂, or ahydrogen-containing gas that includes at least 99% H₂ or at least 98%H₂, or at least 97% H₂, or at least 96% H₂, or at least 95% H₂, is at apressure higher than the current gas pressure at the wellhead 18, e.g.,the shut-in wellhead pressure at a stabilized reservoir-equilibriumpressure, so as to ensure that the hydrogen gas 8 propagates throughoutthe well, i.e., including the hydraulic fractures 32 and natural cracks.In some embodiments, the injection of hydrogen gas is at a pressure thatis at least 100 PSI higher than the current shut-in gas pressure at thewellbore 10 or at least 200 PSI higher, or at least 300 PSI higher, orat least 400 PSI higher, or at least 500 psi higher, or at least 800 PSIhigher. In embodiments, the initial injecting of the hydrogen gas 8 isat a pressure below a maximum gas-recovery pressure PRESSURE_(MAX)encountered in Step S202, or 50 or more PSI lower than PRESSURE_(MAX),or 100 or more PSI lower than PRESSURE_(MAX), or 200 or more PSI lowerthan PRESSURE_(MAX). In embodiments, the initial injecting of thehydrogen gas 8 is at a pressure below a hydrogen fracture extensionpressure H₂FRAC_(EXT) at which the injection of the hydrogen gas 8 wouldcause extension of the existing fractures, including those propagatedduring the hydraulic fracturing of Step S201. The hydrogen fractureextension pressure H₂FRAC_(EXT) is different than the FRAC_(EXT) offracturing fluid discussed in Step S201 because of the weight of thehydraulic column and the fluid friction. In some embodiments,H₂FRAC_(EXT) can be computed from FRAC_(EXT), e.g., to act as a pressurelimit during hydrogen injection. In other embodiments, H₂FRAC_(EXT) canbe measured using a diagnostic fracture injection test (DFIT), or it canbe measured by microseismic monitoring.

In embodiments, the injection of hydrogen gas 8 is at a pressure that isnot higher than the hydrogen-injection fracture extension pressureH₂FRAC_(EXT). Inter alia, this limitation is useful for avoiding, atleast partly, damage outside the wellbore 10 and the extension andbroadening of the existing hydraulic fractures 32, for example toprevent the release of additional free methane in and from the newlyexpanded fractures which affects the hydrogen purity during hydrogenproduction, and to prevent hydrogen loss to the formation. In someembodiments, the injecting of the hydrogen gas 8 is at a pressure thatis at least 200 PSI or at least 500 PSI less than H₂FRAC_(EXT). In someembodiments, the initial injecting of the hydrogen gas 8 is at apressure just below H₂FRAC_(EXT). In an example, the injecting of thehydrogen gas includes injecting the hydrogen gas at a pressure that is100 PSI less than H₂FRAC_(EXT). In some embodiments, surface geophysicalmonitoring, i.e., geophysical monitoring of the geological structurefrom the surface, is performed during hydrogen injection to determinewhether or not hydraulic fractures 32 are being extended by the hydrogeninjection. According to non-limiting examples, surface geophysicalmonitoring can include the use of surface geophysical monitoringequipment 95 such as microseismic arrays or tiltmeters. Gas phasetracers may also be added to the injected hydrogen 8 to see whetherthere is any communication of the hydrogen with adjacent productionwells on the wellhead. Suitable gas phase tracers are tritiated hydrogensuch as HT or T₂ in the range of 3 to 30×10{circumflex over ( )}10Becquerel (Bq) that may be detected at extremely low concentrations innearby production wells. According to a non-limiting example, atracer-gas facility 96 for adding a gas-phase tracer to the injectedhydrogen gas 8 is provided at or near the wellhead 10.

The injection of the hydrogen gas of Step S204 is initiated responsivelyto—and contingent upon—a determination, based on the monitoring or StepS203, that an isotopic signature has reached a trigger criterion fortriggering a transition of the unconventional reservoir 35 fromrecovering the methane-containing gas 5 to injecting a hydrogen gas 8.

In embodiments, a transition to injecting hydrogen gas into thereservoir 35 is triggered upon detecting that an isotopic signature,e.g., δ(¹³C) or δ(C_(X)H_(Y-1)D/C_(X)H_(Y)), is rising. For example,this can include detecting a rise in isotopic signature at twoconsecutive sampling points 980 (FIG. 41 ) or 990 (FIG. 42 ) after therespective minimum isotopic signature δ(¹³C)_(MIN) orδ(C_(X)H_(Y-1)D/C_(X)H_(Y))_(MIN) has been observed. In some examples,hydrogen injection is triggered after detecting a rise in the isotopicsignature at more than consecutive two sampling points. The number ofconsecutive sampling points required for triggering the transition tohydrogen injection is a design choice that can be based on, for example,and not exhaustively: sampling frequency during the monitoring of StepS203, magnitude of signature increase, or detected randomness inmonitored signature values over time. Exemplary trigger points based onan after-minimum rising isotopic signature are at the point labeled 1000in FIG. 41 for δ(¹³C) and at the point labeled 1001 in FIG. 42 forδ(C_(X)H_(Y-1)D/C_(X)H_(Y)). In the case that the trigger point is usedto transition to hydrogen injection, the trajectory of the signaturecurve beyond that trigger point becomes moot. It will be obvious to theskilled artisan that when ratios informing isotopic signatures are‘flipped’, i.e., the numerators and denominators disclosed herein areexchanged with each other, as discussed hereinabove, what is describedin the present disclosure as an ‘increase’ in an isotopic-signaturevalue will actually be a decrease, and vice versa.

Step S205

Step S205 includes recovering stored hydrogen gas 8 through the wellbore10, during the fifth stage of the timeline, between Time=T₃ and Time=T₄.As shown in the example of FIG. 44 , where recovery of thehydrogen-containing gas 8 is represented schematically by thedirectional arrow 204, hydrogen-gas-recovery equipment 80 is provided influid communication with the reservoir 35 via wellbore 10. In someembodiments, the reservoir 35 and wellbore 10 are the same reservoir 35and wellbore 10 as in FIGS. 38, 40 and 43 .

According to the method, the recovered hydrogen-containing gas 8 has anH₂ molar fraction of at least 85%. The H₂ molar fraction of therecovered gas can be directly impacted by the selection of the reservoirin the first stage, e.g., selection of a kerogen-rich reservoir, and/orselection of a kerogen-rich reservoir with low permeability, as theterms have been defined herein. The H₂ molar fraction of the recoveredgas can be directly impacted by the selection of an isotope-signaturetrigger criterion for initiating the injection of hydrogen gas into thereservoir to begin the fourth stage. The proper selection of a triggercriterion in terms of the timing during in the ‘desorbed-gas’ periodshown schematically in FIGS. 41 and 42 can lead to avoiding significantcontamination of the H₂ by CH₄ in the pore spaces or desorbed fromkerogen surfaces, and thus the recovered hydrogen can be of higherpurity, where purity refers to the H₂ molar fraction of the recoveredgas. In various examples, the purity is at least 85%, or at least 86%,or at least 87%, or at least 88%, or at least 89%, or at least 90%, orat least 91%, or at least 92%, or at least 93%, or at least 94%, or atleast 95%, or at least 96%, or at least 97%, or at least 98%, or atleast 99%. In embodiments, the remainder of the gas, i.e., aftersubtracting the H₂ molar fraction, is at least predominantly CH₄.

In some embodiments, not all steps S201, S202, S203, S204, S205 of themethod are performed.

Referring again to FIGS. 43 and 44 , a system 300 for storing andsubsequently recovering a hydrogen-containing gas 8 comprises pumpingarrangements 80 for the hydrogen-containing gas 8. The pumpingarrangements 80 are in fluid communication with the wellbore 10 and areconfigured to inject hydrogen gas 8 therethrough into thehydraulically-fractured reservoir 35. In some embodiments, kerogenconcentration in the reservoir is at least 1% by volume, or at least 2%,or at least 3%. The pumping arrangements 80 include pumps andcompressors, piping (e.g., piping 12), power equipment, and otherequipment as necessary for injecting the hydrogen gas 8. The pumpingarrangements 80 are configured to inject the hydrogen 8 at a pressurehigher than a current shut-in gas pressure at the wellbore. According toembodiments, the reservoir 35 is partially depleted by amethane-containing-gas recovery process.

The gas-recovery process of the reservoir 35 is characterized by aninitial isotope signature value δ(MC)_(INITIAL), a minimum isotopicsignature value δ(MC)_(MIN), and a current isotopic signature valueδ(MC)_(T) greater than δ(MC)_(MIN), wherein MC is a molecular componentin the sampled methane-containing gas according to the embodimentsdisclosed herein, and δ(MC) is based upon an isotope ratio of themolecular component MC of the methane-containing gas. Examples of δ(MC)include δ(¹³C), δ(CH₃D/CH₄), δ(C₂H₅D/C₂H₆), and δ(C₃H₇D/C₃H₈).

The system 300 additionally comprises gas-recovery equipment 80, also influid communication with the reservoir 35 though the wellbore 10. Thegas-recovery equipment 80 is operative to recover a portion of thestored hydrogen-containing gas 8 through the wellbore 10. The system isoperable such that the recovered portion of the hydrogen-containing gas8 has an H₂ molar fraction of at least 85%. In various examples, the H₂molar fraction is at least 85%, or at least 86%, or at least 87%, or atleast 88%, or at least 89%, or at least 90%, or at least 91%, or atleast 92%, or at least 93%, or at least 94%, or at least 95%, or atleast 96%, or at least 97%, or at least 98%, or at least 99%. Inembodiments, the remainder of the gas, i.e., after subtracting the H₂molar fraction, is at least predominantly CH₄.

In some embodiments, the pumping arrangements 80 are operative to injectthe hydrogen-containing gas 8 at a pressure that is at least 500 PSIhigher than the current shut-in gas pressure at the wellbore 10. In someembodiments, the pumping arrangements 90 are operative to inject thehydrogen-containing gas 8 at a pressure that is no more than 100 PSIless than a maximum wellhead pressure of the gas-recovery process of thereservoir 35, PRESSURE_(MAX). In some embodiments, the pumpingarrangements 90 are operative to inject the hydrogen-containing gas 8 ata pressure that is no more than 50 PSI less than PRESSURE_(MAX).

In some embodiments, the system 300 additionally includes surfacegeophysical-monitoring equipment for determining whether hydraulicfractures, e.g., one or more hydraulic fractures, are being extended bythe hydrogen injection. Suitable examples of surfacegeophysical-monitoring equipment include microseismic arrays andtiltmeters.

Referring now to FIG. 45 , a method is disclosed for storing andsubsequently recovering a hydrogen gas. As illustrated by the flowchartin FIG. 45 , the method comprises Steps S211, S212, S213 and S214, whichare discussed in the following paragraphs. A suitable system for use inperforming the method is the system 300 described above in connectionwith FIGS. 43 and 44 .

Step S211

Step S211 includes sampling, at a plurality of times, amethane-containing gas 5 recovered from a geological formation 30through a horizontal wellbore 10. In non-limiting examples, the samplingis carried out periodically at sampling points such as exemplarysampling points 980 shown in FIG. 41 or sampling points 990 shown inFIG. 42 . Sampling points, in embodiments, are chosen to have sufficientfrequency for detecting an increase in an isotopic signature followingachieving a minimum value of the isotopic signature. The time betweensampling points is not necessarily constant.

Step S212

Step S212 includes monitoring an isotopic signature of a molecularcomponent of the sampled methane-containing gas, and as such isidentical to Step S203 discussed hereinabove. The discussion of StepS203 is not repeated here, for the sake of brevity.

Step S213

Step S213 includes injecting hydrogen gas 8 through a horizontalwellbore 10 into a hydraulically-fractured, kerogen-rich, andpartially-depleted reservoir of a methane-containing gas 3, at apressure higher than a current shut-in gas pressure at the wellhead 10.For the purposes of the present disclosure, the term ‘kerogen-rich’refers to a kerogen concentration of at least 1% organic content byvolume, or at least 2%, or at least 3% The partial depletion of thepartially-depleted reservoir is by a methane-containing-gas recoveryprocess that is characterized by an initial isotope signature valueδ(MC)_(INITIAL), a minimum isotopic signature value δ(MC)_(MIN), and acurrent isotopic signature value δ(MC)_(T) greater than δ(MC)_(MIN),wherein MC is a molecular component in the sampled methane-containinggas according to the embodiments disclosed herein, and δ(MC) is basedupon an isotope ratio of the molecular component MC of themethane-containing gas. Examples of δ(MC) include δ(¹³C), δ(CH₃D/CH₄),δ(C₂H₅D/C₂H₆), and δ(C₃H₇D/C₃H₈).

In some embodiments, the methane-containing-gas recovery process isadditionally characterized by a maximum wellhead pressure ofPRESSURE_(MAX), and the injecting of the hydrogen gas 8 of Step S213includes injecting the hydrogen gas 8 at a pressure that is 100 or morePSI less than PRESSURE_(MAX), i.e., at most (PRESSURE_(MAX)−100 PSI). Inembodiments, the injecting of the hydrogen gas 8 includes injecting thehydrogen gas 8 at a pressure that is at least 500 PSI higher than thecurrent shut-in gas pressure at the wellhead 10.

In some embodiments, the injecting of the hydrogen gas 8 is at apressure that is at least 200 PSI or at least 500 PSI less than thehydrogen fracture extension pressure H₂FRAC_(EXT). In some embodiments,the initial injecting of the hydrogen gas 8 is at a pressure just belowthe hydrogen fracture extension pressure H₂FRAC_(EXT). In someembodiments, surface geophysical monitoring, i.e., geophysicalmonitoring of the geological structure 30 from the surface, is performedduring hydrogen injection to determine whether hydraulic fractures 32are being extended by the hydrogen injection. According to non-limitingexamples, surface geophysical monitoring can include the use of surfacegeophysical monitoring equipment 95 such as microseismic arrays ortiltmeters. According to a non-limiting example, a tracer-gas facility96 for adding a gas-phase tracer to the injected hydrogen gas 8 isprovided at or near the wellhead 10.

Step S214

Step S214 includes recovering a portion of the stored hydrogen gas 8through the wellbore 10. The recovered hydrogen gas is mostly purehydrogen, i.e., has an H₂ molar fraction of at least 85%, or at least86%, or at least 87%, or at least 88%, or at least 89%, or at least 90%,or at least 91%, or at least 92%, or at least 93%, or at least 94%, orat least 95%, or at least 96%, or at least 97%, or at least 98%, or atleast 99%. The remainder of the recovered gas mix can include methaneand other hydrocarbon gases such as ethane and propane, andnon-hydrocarbon gases such as carbon dioxide and nitrogen.

According to yet further embodiments of the invention, an unconventionalgas reservoir can be suitable for long-term and/or short-term storage ofhydrogen gas after partial depletion of the natural gas. The timeline ofFIG. 46 shows a sequence of stages associated with the use of apartially depleted unconventional gas reservoir for storage and recoveryof hydrogen in accordance with embodiments.

In a first stage, before Time=T₀, a suitable gas-containing reservoir isselected, e.g., based on one or more technical and/or economic selectioncriteria, and a deep horizontal wellbore is established in thereservoir. Non-limiting examples of technical selection criteriainclude, and not exhaustively: low permeability, e.g., permeabilitylower than 10⁻¹ millidarcy (mD), lower than 10⁻² mD, lower than 10⁻³ mD,or lower than 10⁻⁴ mD; proportion of organic matter (i.e., kerogen),e.g., at least 1% kerogen, at least 2% kerogen, or at least 3% kerogen;and distribution of pore volumes in the kerogen.

In a second stage, between Time=T₀ and Time=T₁, the reservoir ishydraulically fractured. The deep horizontal wellbore is perforated forhydraulic fracturing, e.g., by a perforating gun. A fracturing fluid isinjected under pressure through a horizontal wellbore into thegeological formation to effect the fracturing by propagation andexpansion of cracks in the rock structure. The hydraulic fracturingprocess is used to facilitate and/or accelerate the recovery of gas fromthe reservoir by opening cracks in the deep shale formations. As isknown in the art, successive sections of the reservoir along thewellbore are fractured sequentially and not simultaneously. An exampleof a suitable fracturing fluid is a mixture of water, a proppant such assand or a ceramic, and/or a chemical or polymer to improve a flowcharacteristic such as the water's surface friction and/or to act as alubricant. In other examples, a suitable fracturing fluid can include anenergized fluid, e.g., a fluid including at least one compressed orcompressible gas-phase material, or an oil-based fluid.

In a third stage, between Time=T₁ and Time=T₂, natural gas is recoveredfrom the hydraulically-fractured reservoir. The gas recovery processover time is characterized by one or more isotope ratios that changeover time, as will be further described hereinbelow.

In a fourth stage, between Time=T₂ and Time=T₃, hydrogen gas is injectedinto the reservoir. In embodiments, the transition from the third stageto the fourth stage, at Time=T₂, is based on a trigger criterion. Thetrigger criterion can include a trigger criterion that corresponds to achange in an isotope ratio matching an isotope-signature triggercriterion. Matching an isotope-signature trigger criterion can be basedon projecting isotope ratio values of the reservoir based on valuesobtained from a core sample extracted from the reservoir. The coresample values can include isotope ratio values relating to variousmeasured pressures, e.g., in an instrumented core sample holder. Duringthe economic life of the unconventional gas reservoir in the thirdstage, matching the isotope-signature trigger criterion involvesmonitoring the pressure in the reservoir to determine when a reservoirpressure matches a core-sample pressure that corresponds to one or morecore-sample isotope ratio values associated with an isotope-signaturetrigger criterion. According to embodiments, the projecting can provideadvance indications of when the reservoir will reach theisotope-signature trigger criterion so that the transition to injectionof hydrogen into the reservoir can begin.

An example of an isotopic-signature trigger criterion suitable fortriggering a transition of operation of an unconventional gas reservoirto injecting compressed hydrogen for long- and/or short-term storage isa δ(¹³C) isotopic signature based on a ratio of ¹³C to ¹²C (or viceversa). Another example of a suitable isotopic-signature triggercriterion for triggering a transition to hydrogen injection is aδ(C_(X)H_(Y-1)D/C_(X)H_(Y)) isotopic signature, which represents a ratioof deuterated hydrocarbon molecules to non-deuterated molecules where Xand Y are the number of carbon and hydrogen atoms, respectfully. Thisexpression (and similar expressions throughout the present disclosure),which include a single deuteron in the numerator, is used forconvenience and is not intended to imply that all deuterated hydrocarbonmolecules detected are specifically monodeuterated molecules. A smalland typically insignificant number of molecules are not monodeuterated,i.e., have multiple deuterons in a molecule, and such molecules areincluded in any analysis of monitored isotope signatures.

In a fifth stage, between Time=T₃ and Time=T₄, stored hydrogen gas isrecovered from the reservoir. The recovered hydrogen gas is mostly purehydrogen, i.e., has an H₂ molar fraction of at least 85%, or at least86%, or at least 87%, or at least 88%, or at least 89%, or at least 90%,or at least 91%, or at least 92%, or at least 93%, or at least 94%, orat least 95%, or at least 96%, or at least 97%, or at least 98%, or atleast 99%. The remainder of the recovered gas mix can include methane,other hydrocarbon gases such as ethane and propane, and non-hydrocarbongases such as carbon dioxide and nitrogen.

In a sixth stage, after Time=T₄, the injecting and recovering ofhydrogen can be cycled. The sixth stage can thus be considered arepetition or cycling of the fourth and fifth stages. In someembodiments, when the hydrogen recovery of the fifth stage reaches ahydrogen-production trigger criterion, operation of reservoir reverts toinjecting hydrogen, inter alia to increase pressure and improve futurehydrogen recovery volume. In some embodiments, hydrogen is cycled daily,meaning that within a single diurnal cycle, hydrogen is injected, andthen recovered. The diurnal cycle can repeat indefinitely. In some suchembodiments, the fourth-stage injection of hydrogen can be up to a ‘baselevel’, on top of which there is a daily cycle of fluctuation, so thatthe daily recovery cycle is at a sufficiently high pressure to ensurerapid recovery.

Any or all of the times T₀, T₁, T₂, T₃ and T₄ can be points in time orperiods of time, for example, days, weeks or months.

Referring now to FIG. 47A, a method is disclosed for storing hydrogengas in a kerogen-rich geological formation, including for subsequentlyrecovering the hydrogen therefrom. As illustrated by the flowchart inFIG. 47A, the method comprises Steps S301, S302, S303, S304 and S305,which are discussed in the following paragraphs.

Step S301

Step S301 includes injecting a fracturing fluid through a horizontalwellbore into the geological formation to cause fracturing within thegeological formation. Arrangements for injecting a fracturing fluid intoa geological formation are illustrated schematically in FIG. 48 . Ageological formation 30, shown in accordance with the descriptionhereinabove of the second stage between Time=T₀ and Time=T₁, includes anorganic-rich shale deposit (also called a shale formation). Hydraulicfracturing equipment 70 is disposed at a wellhead 18. The wellhead 18 islocated at a wellpad 19 and is in fluid communication with anunconventional gas reservoir 35 located within the shale formation 30,which in the non-limiting example of FIG. 48 is below the water table27.

The wellbore 10, including perforated casing, is horizontally orientedat the depth of the shale formation 30, and can extend horizontally fortens, hundreds or thousands of meters. As indicated by the directionalarrow 201, a hydraulic-fracturing fluid 3 is injected into (and through)the wellbore 10 and thence into fractures 32. The injecting is effectiveto increase pressure at the target depth of the reservoir 35, e.g.,based on the depth of the wellbore, to exceed that of the fracturegradient of the rock. At a fracture-initiating pressure known as a‘breakdown pressure’, the deep rock surrounding the wellbore 10 crackswith pressure. Once fracturing is initiated, pressure at the wellhead 18drops and then starts increasing, as the fracturing fluid 3 permeatesthe rock, further extending the fractures. This occurs at thefracture-extending pressure FRAC_(EXT). Fractures predominantlyperpendicular to the wellbore may reach lengths of a few hundred feetlong; the height of the fractures 32 is controlled by the stresses inthe rock formations above and below the wellbore.

FIG. 48 illustrates a single well, but a single geological formation 30or a single unconventional gas reservoir 35 can be serviced by multiplewells, as shown in FIG. 49 . FIG. 49 illustrates multiple wells(indicated by wellbores 10) at each wellpad 19, and multiple wellpads 19servicing the gas reservoir 35. In the non-limiting example of FIG. 49 ,gas flows through a network of transmission nodes to a central treatmenthub that services the multiple wells. The example of FIG. 49 shows 8wells, i.e., wellbores 10, operating from each wellpad 19. In otherexamples, not illustrated, there can be any number of wells, such as forexample, 16, 32 or 64 wells. Each well comprises a wellhead 18 and awellbore 10. Pressure and flow measurements may be made using pressureand flow gauges at the wellhead 18 while flowing or during shut-in.Pressure may also be measured downhole using downhole pressure gauges.

Step S302

Step S302 includes recovering a methane-containing gas 5 through thewellbore. Referring to FIG. 50 , gas-recovery activity at the wellhead18 is illustrated during the third stage of the timeline of FIG. 46 ,i.e., between Time=T₁ and Time=T₂. As indicated by directional arrow202, natural gas 5 is recovered through the wellbore 10 from thereservoir 35, including from the hydraulic fractures 32, and processedby gas recovery equipment 80 which is in fluid communication with thewellbore 10 at the wellhead 18. Recovery of the gas 5 reaches a maximumpressure PRESSURE_(MAX) after a short period (weeks or months) after gasrecovery begins, and declines thereafter.

Step S303

Step S303 includes projecting a reservoir isotope ratio valueI-RATIO_(RES) for the recovered methane-containing gas 5 at each of aplurality of corresponding reservoir pressures PRESSURE_(RES) atrespective reservoir times T_(RES).

The projecting is done based on an isotope ratio value I-RATIO_(CS)measured in gas recovered from a core sample in a core-sample chamber(or, equivalently, core-sample holder), e.g., in a laboratory. The coresample is taken from the unconventional reservoir 35, a kerogen-richgeological formation, in which hydrogen is to be stored. In someembodiments, the core sample is taken from or near a specific well 11 ofinterest.

An isotope ratio value I-RATIO_(CS) corresponds to a pressurePRESSURE_(CS) in the core-sample holder at any time T_(CS). T_(CS)represents, for example, how much time has elapsed since the beginningof off-gassing by the core sample in a particular off-gassing session inthe core-sample chamber. An off-gassing session of the core sample isgenerally started from an initial PRESSURE_(CS) being set to equal theinitial reservoir pressure measured at the beginning of Step S302. Boththe isotope ratio value I-RATIO_(CS)(T_(CS)) and thePRESSURE_(CS)(T_(CS)) are measured at each time T_(CS). When anisotopic-signature trigger criterion is reached, e.g., a desired valueof isotope ratio value I-RATIO_(CS), the corresponding core-samplepressure value PRESSURE_(CS) for the same time T_(CS) is used forsetting the ‘given’ reservoir pressure PRESSURE_(RES). Thus, measuringthe given reservoir pressure PRESSURE_(RES)(T_(RES)) at the reservoir ata time T_(RES) indicates that the current isotope ratio valueI-RATIO_(RES)(T_(RES)) in the reservoir at the same time T_(RES)corresponds to reaching the isotopic-signature trigger criterion in thereservoir. The nomenclature T_(RES) is introduced to differentiateelapsed time of gas recovery in the reservoir (T_(RES)) from elapsedtime of gas recovery from a core sample (T_(CS)), e.g., in a laboratory,which can be used in the projecting of Step S303.

The isotope ratio value I-RATIO_(RES)(T_(RES)) relates to one or morecomponent gas molecules in the recovered methane-containing gas 5 ateach of a plurality of corresponding reservoir pressuresPRESSURE_(RES)(T_(RES)), i.e., values of PRESSURE_(RES) at respectivereservoir times T_(RES). The reservoir times T_(RES) can be any timeduring the second stage, i.e., recovery of methane-containing gas 5 fromthe reservoir 35. T_(RES) can be measured, for example, as the timeelapsed from the beginning of gas recovery at Time=T₁, which can be atthe beginning of Step S302.

A first example of a suitable reservoir isotope ratio valueI-RATIO_(RES) for monitoring as an isotopic-signature trigger criterionis a δ(¹³C) isotopic signature based on a ratio of ¹³C to ¹²C (or viceversa).

A second example of a suitable reservoir isotope ratio valueI-RATIO_(RES) for monitoring as an isotopic-signature trigger criterionis one that is based on a deuterium-isotope ratio of ahydrocarbon-molecule component found in the methane containing gas.

A first example of a hydrocarbon-molecule component is methane (CH₄). Asuitable reservoir isotope ratio value I-RATIO_(RES) for monitoring asan isotopic-signature trigger criterion relates to monodeuteratedmethane: CH₃D/CH₄ or, equivalently in terms of suitability,CH₃D/(CH₄+CH₃D). As discussed earlier, there can be some methanemolecules with multiple protium atoms substituted by deuterium atoms andthese are included in the analysis along with the monodeuterated methanemolecules.

A second example of a hydrocarbon-molecule component is ethane (C₂H₆). Asuitable reservoir isotope ratio value I-RATIO_(RES) for monitoring asan isotopic-signature trigger criterion relates to monodeuteratedethane: C₂H₅D/C₂H₆ or, equivalently in terms of suitability,C₂HSD/(C₂H₆+C₂HSD). As discussed earlier, there can be some ethanemolecules with multiple protium atoms substituted by deuterium atoms andthese are included in the analysis along with the monodeuterated ethanemolecules.

A third example of a hydrocarbon-molecule component is propane (C₃H₈). Asuitable reservoir isotope ratio value I-RATIO_(RES) for monitoring asan isotopic-signature trigger criterion relates to monodeuteratedpropane: C₃H₇D/C₃H₈ or, equivalently in terms of suitability,C₃H₇D/(C₃H₈+C₃H₇D). As discussed earlier, there can be some propanemolecules with multiple protium atoms substituted by deuterium atoms andthese are included in the analysis along with the monodeuterated propanemolecules.

A fourth example of a hydrocarbon-molecule component is butane (C₄H₁₀).A suitable reservoir isotope ratio value I-RATIO_(RES) for monitoring asan isotopic-signature trigger criterion relates to monodeuteratedbutane: C₄H₉D/C₄H₁₀ or, equivalently in terms of suitability,C₄H₉D/(C₄H₁₀+C₄H₉D). As discussed earlier, there can be some butanemolecules with multiple protium atoms substituted by deuterium atoms andthese are included in the analysis along with the monodeuterated butanemolecules.

A fifth example of a hydrocarbon-molecule component is pentane (C₅H₁₂).A suitable reservoir isotope ratio value I-RATIO_(RES) for monitoring asan isotopic-signature trigger criterion relates to monodeuteratedpentane: C₅H₁₁D/C₅H₁₂ or, equivalently in terms of suitability,C₅H₁₁D/(C₅H₁₂+C₅H₁₁D). As discussed earlier, there can be some pentanemolecules with multiple protium atoms substituted by deuterium atoms andthese are included in the analysis along with the monodeuterated pentanemolecules.

Collectively, methane, ethane, propane, butane, and pentane are membersof the C1-C5 alkane group, and monodeuterated methane, monodeuteratedethane, monodeuterated propane, monodeuterated butane and monodeuteratedpentane are members of the monodeuterated C1-C5 alkane group.

According to embodiments, Step S303 is performed by carrying out twosub-steps S303A and S303B, which are illustrated in the flowchart ofFIG. 47B:

Step S303A: sampling a gas mixture recovered from a core sample todetermine a plurality of core-sample value-pairs—a core-sample isotoperatio I-RATIO_(CS)(T_(CS)) value and a respective core-sample pressurevalue PRESSURE_(CS)(T_(CS))—for respective core-sample times T_(CS).Each core-sample value-pair, i.e., for each sampling time T_(CS),includes a core-sample isotope ratio I-RATIO_(CS)(T_(CS)) value and arespective core-sample pressure value PRESSURE_(CS)(T_(CS)).

FIGS. 51A and 51B show block diagrams of laboratory apparatus 500configured for use in Step S303A for measuring values of isotopicsignatures and/or isotope ratios, e.g., an isotope ratio value I-RATIO,using one or more core samples 550 extracted from the unconventional gasreservoir 35. The reference sample holder 517 provides a comparisonmeasurement of the amount of adsorbed gas, as per measurements ofLangmuir isotherms. A pump (not shown) can be used to evacuate the coresample holder 511 containing the sample. Pressure Control Valves (PCV)508 are provided for changing the gas pressure of the measurements inthe core sample holder 511 and the reference holder 517. Pressure (P)509 and Temperature (T) 510 sensors are located in the core sampleholder 511 and reference cell, as shown in FIG. 51A. FIG. 51B shows anoperational situation in which the core sample holder 511 contains acore sample 550.

In some embodiments, Step S303A is performed by carrying out foursub-steps S303A-1, S303A-2, S303A-3, and S303A-4, which are illustratedin the flowchart of FIG. 47C:

-   -   Step S303A-1: receiving a core sample obtained from the gas        reservoir 35 in a core-sample holder 511. In an exemplary        procedure, the core sample 550 is first dried and weighed, then        placed in the temperature-controlled core sample holder 511. The        core sample 550 delivered from the unconventional gas reservoir        35 is mostly depleted of natural gas by the time it reaches the        lab. In the lab, it must be re-saturated with natural gas at a        reservoir pressure and allowed to equilibrate. In an example,        the core sample 550 is re-saturated to an initial reservoir        pressure of the reservoir 35 from which it is taken. In another        example, the core sample 550 is re-saturated to the        PRESSURE_(RES) of the reservoir 35 at the time that the core        sample 550 was taken. In another example, the core sample 550 is        re-saturated to a pressure of the reservoir 35 at the time of        the re-saturating in the core-sample holder 511. In embodiments,        it can be desirable for the pressure of the re-saturation in the        core-sample holder 511 to match a relevant pressure in the        reservoir, while in other embodiments, arithmetic adjustments        can be made to calculations of Step S303 to overcome any        discrepancy between an initial core-sample holder pressure        PRESSURE_(CS) and an unmatched reservoir pressure        PRESSURE_(RES).    -   Step S303A-2: introducing a methane-containing gas (or other        gas, as appropriate) with a known isotope ratio I-RATIO into the        core-sample holder, while regulating an internal gas pressure of        the core-sample holder to an initial core-sample holder pressure        PRESSURE_(CS-INIT). In the non-limiting example of FIGS. 51A-B,        two gases are provided for testing: He 522 and CH₄ 523, although        in some other exemplary laboratory setups (not shown) other        gases such as ethane (C₂H₆), propane (C₃H₈), butane (C₄H₁₀) or        pentane (C₅H₁₂) are used in the same manner as described here        for CH₄, mutatis mutandis. The CH₄ gas 523 (for example) can        have a known (i.e., measured)¹³C/¹²C isotopic ratio and/or a        measured CH₃D/CH₄ isotopic ratio (a deuterated-to-non-deuterated        methane ratio).    -   Step S303A-3: periodically sampling a gas mixture produced by        the core sample in the core-sample holder at a core-sample        pressure PRESSURE_(CS)(T_(CS)). The periodicity of the sampling        need not be constant during the off-gassing process. Any number        or timing of sampling times T_(CS) may be selected. In an        exemplary analytical procedure, after pressure in the        core-sample holder 511 is brought to a predetermined pressure        that matches the initial pressure in the conventional gas        reservoir 35 from which the core sample 550 was taken, the core        sample is sealed in by the shutoff valve 525 and allowed to        equilibrate with the methane gas 523. After equilibration, the        off-gassing core sample is then allowed to produce gas through        the PCV 508. Sampling (and analysis) of the gas produced in the        core sample holder 511 of the lab setup 500 of FIGS. 51A-B as        required for the sampling to be carried out periodically and at        different pressures, for example with gas sampling cylinders        565.    -   FIG. 52 illustrates a non-limiting example of a periodic        sampling regime. FIG. 52 shows a series of points 1980 along the        x-axis, which represents time T_(CS), in hours, since the        beginning of off-gassing of a given core sample 550. The y-axis        represents values of the isotopic signature δ(¹³C) for each        T_(CS) value. An isotope-trigger point 2000 is the specific        point (T_(CS) value) 1980 at which the measured/calculated        δ(¹³C) value reaches a predetermined trigger criterion based on        the isotopic signature δ(¹³C). In other examples, other isotopic        signatures such as, and not exhaustively, δ(CH₃D/CH₄),        δ(C₂H₅D/C₂H₆), or δ(C₃H₇D/C₃H₈) can be measured/calculated for        each point (T_(CS) value) 1980. As shown in the example of FIG.        52 , additional more samples can be taken, e.g., at points 1980        _(X), 1980 _(Y), 1980 _(Z), after reaching the isotope-trigger        point 2000 to check whether the trend of the isotope signature        values δ(¹³C) continues. Once it becomes clear that the isotope        ratio is trending away from the trigger point, it is possible to        stop sampling.    -   Step S303A-4: determining a core-sample isotope ratio        I-RATIO_(CS)(T_(CS)) of the sampled gas mixture for each        periodic sampling corresponding to respective values of        PRESSURE_(CS)(T_(CS)). A core-sample value-pair can be measured        and/or calculated for each respective core-sample time T_(CS),        where each core-sample value-pair includes a core-sample isotope        ratio I-RATIO_(CS)(T_(CS)) value and a respective core-sample        pressure value PRESSURE_(CS)(T_(CS)). The δ(¹³C) and/or the        δ(CH₃D/CH₄)—or in other examples, δ(C₂H₅D/C₂H₆) or δ(C₃H₇D/C₃H₈)        isotope ratios in the gas sampling cylinders are measured by gas        chromatography and isotope ratio mass spectrometry 550. The        helium gas 522 can be used, inter alia, as a carrier gas for the        gas chromatography.

Step S303B: matching PRESSURE_(RES)(T_(RES)) values with respectivePRESSURE_(CS)(T_(CS)) values, to project I-RATIO_(RES)(T_(RES)) valuesbased on I-RATIO_(CS)(T_(CS)) values corresponding to the matchedrespective PRESSURE_(CS)(T_(CS)) values. In this manner, at any timeduring the productive life of the reservoir or well, it is possible toproject that a desired isotope ratio has been reached in the reservoir35 or well 11.

We now refer to FIGS. 52, 53, 54 and 55 . These figures, when takentogether, can be used to illustrate the process of Step S303B. FIG. 52 ,as mentioned previously, illustrates the identification of anisotope-trigger point 2000 in the core-sample laboratory 500. Theisotope-trigger point 2000 corresponds to a core-sample value pair forthe respective core-sample time T_(CS) of isotope-trigger point 2000.

As shown in FIG. 53 , The core-sample pair for the isotope-trigger point2000 at time T_(CS)=n corresponds to a core sample pressure ofPRESSURE_(CS)(T_(CS)=n) and an isotope signature or ratioI-RATIO_(CS)(T_(CS)=n), which matches the isotope-trigger value.

In the reservoir 35, as shown in FIG. 54 , the reservoir pressurePRESSURE_(RES)(T_(RES)) is monitored, and at time T_(RES)=m, thereservoir pressure PRESSURE_(RES)(T_(RES)=m) matches the core samplepressure PRESSURE_(CS)(T_(CS)=n) of isotope-trigger point 2000 of FIG.53 . At the point where the pressures match, as indicated by T_(RES)point 2002 at T_(RES)=m, the reservoir isotopic signature valueI-RATIO_(RES)(T_(RES=m)) equals the isotope trigger valueI-RATIO_(CS)(T_(CS=n))—i.e., the core-sample isotopic signature valuecorresponding to the isotope-trigger point 2000 of FIG. 53 .

Step S304

Step S304 includes injecting hydrogen gas through the wellbore 10according to an isotopic-signature trigger criterion, based uponreservoir isotope ratio values I-RATIO_(RES)(T_(RES)) projected in StepS303. According to the method, it can be desirable to initiate injectionof hydrogen into a partially-depleted well at T_(RES)=m, correspondingto the isotope-trigger point 2002 of FIG. 54 .

Step S304 takes place during the fourth stage of the timeline, betweenTime=T₂ and Time=T₃. As shown in the example of FIG. 56 , whereinjection of the hydrogen 8 is represented schematically by thedirectional arrow 203, hydrogen-gas-pumping arrangements 90 are providedin fluid communication with the reservoir 35 via wellbore 10. Inembodiments, the reservoir 35 and wellbore 10 are the same reservoir 35and wellbore 10 as in FIGS. 48 and 50 .

The skilled artisan will understand that the transition from the thirdstage of recovering methane to the fourth stage of injecting hydrogen atTime=T₂ can involve one or more preparatory steps performed betweenSteps S303 and S304 of the method. For example, it can be desirable toclose valves at the surface to cause pressure in the reservoir 35 toreach an equilibrium pressure. This can include closing the valves atthe surface to end gas recovery, and allowing time for the wellheadpressure to increase from a flowing wellhead pressure to a shut-inwellhead pressure. Over a period of weeks the shut-in wellhead pressurerises to an equilibrium pressure that is approximately equal toreservoir pressure.

The injection of the hydrogen gas 8, e.g., pure H₂, or ahydrogen-containing gas that includes at least 99% H₂ or at least 98%H₂, or at least 97% H₂, or at least 96% H₂, or at least 95% H₂, is at apressure higher than the current gas pressure at the wellhead 18, e.g.,the shut-in wellhead pressure at a stabilized reservoir-equilibriumpressure, so as to ensure that the hydrogen gas 8 propagates throughoutthe well, i.e., including the hydraulic fractures 32 and natural cracks.In some embodiments, the injection of hydrogen gas is at a pressure thatis at least 100 PSI higher than the current shut-in gas pressure at thewellbore 10 or at least 200 PSI higher, or at least 300 PSI higher, orat least 400 PSI higher, or at least 500 psi higher, or at least 800 PSIhigher. In embodiments, the initial injecting of the hydrogen gas 8 isat a pressure below the maximum gas-recovery pressure PRESSURE_(MAX) ofStep S302, or 50 or more PSI lower than PRESSURE_(MAX), or 100 or morePSI lower than PRESSURE_(MAX), or 200 or more PSI lower thanPRESSURE_(MAX). In embodiments, the initial injecting of the hydrogengas 8 is at a pressure below a hydrogen fracture extension pressureH₂FRAC_(EXT) at which the injection of the hydrogen gas 8 would causeextension of the existing fractures, including those propagated duringthe hydraulic fracturing of Step S301. The hydrogen fracture extensionpressure H₂FRAC_(EXT) is different than the FRAC_(EXT) of fracturingfluid discussed in Step S301 because of the weight of the hydrauliccolumn and the fluid friction. In some embodiments, H₂FRAC_(EXT) can becomputed from FRAC_(EXT), e.g., to act as a pressure limit duringhydrogen injection. In other embodiments, H₂FRAC_(EXT) can be measuredusing a diagnostic fracture injection test (DFIT), or it can be measuredby microseismic monitoring.

In embodiments, the injection of hydrogen gas 8 is at a pressure that isnot higher than the hydrogen-injection fracture extension pressureH₂FRAC_(EXT). Inter alia, this limitation is useful for avoiding, atleast partly, damage outside the wellbore 10 and the extension andbroadening of the existing hydraulic fractures 32, for example toprevent the release of additional free methane in and from the newlyexpanded fractures which affects the hydrogen purity during hydrogenproduction, and to prevent hydrogen loss to the formation. In someembodiments, the injecting of the hydrogen gas 8 is at a pressure thatis at least 200 PSI or at least 500 PSI less than H₂FRAC_(EXT). In someembodiments, the initial injecting of the hydrogen gas 8 is at apressure just below H₂FRAC_(EXT). In an example, the injecting of thehydrogen gas includes injecting the hydrogen gas at a pressure that is100 PSI less than H₂FRAC_(EXT). In some embodiments, surface geophysicalmonitoring, i.e., geophysical monitoring of the geological structurefrom the surface, is performed during hydrogen injection to determinewhether hydraulic fractures 32 are being extended by the hydrogeninjection. According to non-limiting examples, surface geophysicalmonitoring can include the use of surface geophysical monitoringequipment 95 such as microseismic arrays or tiltmeters. Gas phasetracers may also be added to the injected hydrogen 8 to see whetherthere is any communication of the hydrogen with adjacent productionwells on the wellhead. Suitable gas phase tracers are tritiated hydrogensuch as HT or T₂ in the range of 3 to 30×10{circumflex over ( )}10Becquerel (Bq) that may be detected at extremely low concentrations innearby production wells. According to a non-limiting example, atracer-gas facility 96 for adding a gas-phase tracer to the injectedhydrogen gas 8 is provided at or near the wellhead 10.

The injection of the hydrogen gas of Step S304 is initiated responsivelyto—and contingent upon—a determination, based on the monitoring or StepS303, that an isotopic signature has reached a projected triggercriterion for triggering a transition of the unconventional reservoir 35from recovering the methane-containing gas 5 to injecting a hydrogen gas8. For example, a carbon isotope ratio in the methane gas produced fromthe shale gas reservoir 35 changes over time during the commercial lifeof the unconventional gas reservoir, and the inventors have found thatthese changes, when can be monitored in order to project matching a‘trigger criterion’ that can be used, according to embodiments, totrigger a transition to injecting H₂ into the reservoir.

Step S305

Step S305 includes recovering stored hydrogen gas 8 through the wellbore10, during the fifth stage of the timeline, between Time=T₃ and Time=T₄.As shown in the example of FIG. 55 , where recovery of thehydrogen-containing gas 8 is represented schematically by thedirectional arrow 204, hydrogen-gas-recovery equipment 80 is provided influid communication with the reservoir 35 via wellbore 10. Inembodiments, the reservoir 35 and wellbore 10 are the same reservoir 35and wellbore 10 as in FIGS. 48, 50 and 54 . The recoveredhydrogen-containing gas 8 can include, as illustrated schematically inFIG. 56 , bulk-phase H₂ in hydraulic fractures, H₂ in kerogen porespaces, H₂ adsorbed on kerogen surfaces, H₂ dissolved in kerogen, and/orbulk-phase H₂ contained in the non-organic pores or adsorbed on clays ofthe matrix of the geological formation 30.

According to the method, the recovered hydrogen-containing gas 8 has anH₂ molar fraction of at least 85%. The H₂ molar fraction of therecovered gas can be directly impacted by the selection of the reservoirin the first stage, e.g., selection of a kerogen-rich reservoir, and/orselection of a kerogen-rich reservoir with low permeability, as theterms have been defined herein. The H₂ molar fraction of the recoveredgas can be directly impacted by the selection of a flow-rate triggercriterion FLOW_(TRIGGER) with respect to the current flow rateFLOW_(CURRENT) of natural gas for initiating the injection of hydrogengas into the reservoir to begin the fourth stage. In embodiments,FLOW_(TRIGGER) is chosen to correspond to a state of the reservoir inwhich pore methane and kerogen-adsorbed methane is largely alreadyrecovered, such that the hydrogen gas replaces the methane in thefaster-recovery locations of the shale formation. The proper selectionof a FLOW_(TRIGGER) in terms of the timing of the initiating can lead toavoiding significant contamination of the H₂ by CH₄ in the pore spacesor desorbed from kerogen surfaces, and thus the recovered hydrogen canbe of higher purity, where purity refers to the H₂ molar fraction of therecovered gas. In various examples, the purity is at least 85%, or atleast 86%, or at least 87%, or at least 88%, or at least 89%, or atleast 90%, or at least 91%, or at least 92%, or at least 93%, or atleast 94%, or at least 95%, or at least 96%, or at least 97%, or atleast 98%, or at least 99%. In embodiments, the remainder of the gas,i.e., after subtracting the H₂ molar fraction, is at least predominantlyCH₄.

In some embodiments, not all the steps S301, S302, S303, S304, S305 ofthe method, including respective sub-steps are performed.

Referring again to FIGS. 56 and 57 , a system 400 for storing andsubsequently recovering a hydrogen-containing gas 8 comprises pumpingarrangements 80 for the hydrogen-containing gas 8. The pumpingarrangements 80 are in fluid communication with the wellbore 10 and areconfigured to inject hydrogen gas 8 therethrough into thehydraulically-fractured reservoir 35. In some embodiments, kerogenconcentration in the reservoir is at least 1% by volume, or at least 2%,or at least 3%. The pumping arrangements 80 include pumps andcompressors, piping (e.g., piping 12), power equipment, and otherequipment as necessary for injecting the hydrogen gas 8. The pumpingarrangements 80 are configured to inject the hydrogen 8 at a pressurehigher than a current shut-in gas pressure at the wellbore. According toembodiments, the reservoir 35 is partially depleted by amethane-containing-gas recovery process.

The gas-recovery process of the reservoir 35 is characterized, asillustrated schematically in FIG. 57 , by a stretched exponential, or insome embodiments, hyperbolic, decline in gas recovery rate from a peakflow rate of FLOW_(MAX) to a minimum flow rate of FLOW_(MIN) which atleast 10% of FLOW_(MAX) and not more than 15% of FLOW_(MAX). Inembodiments, FLOW_(MIN) is at least 10% of FLOW_(MAX) and not more than20% of FLOW_(MAX). In other embodiments, FLOW_(MIN) is at least 15% ofFLOW_(MAX) and not more than 20% of FLOW_(MAX). In some embodiments, thefluid flow regime of the reservoir is substantially diffusional. Thephrase ‘substantially diffusional’ means that at least 50% of the gasrecovered at the end of the gas recovery process was from diffusion. orat least 60%, or at least 70%, or at least 80%, or at least 90%, or atleast 95%. In various examples, the diffusion includes Knudsen, surfaceand/or solution diffusion.

The system 400 additionally comprises gas-recovery equipment 80, also influid communication with the reservoir 35 though the wellbore 10. Thegas-recovery equipment 80 is operative to recover a portion of thestored hydrogen-containing gas 8 through the wellbore 10. The system isoperable such that the recovered portion of the hydrogen-containing gas8 has an H₂ molar fraction of at least 85%. In various examples, the H₂molar fraction is at least 85%, or at least 86%, or at least 87%, or atleast 88%, or at least 89%, or at least 90%, or at least 91%, or atleast 92%, or at least 93%, or at least 94%, or at least 95%, or atleast 96%, or at least 97%, or at least 98%, or at least 99%. Inembodiments, the remainder of the gas, i.e., after subtracting the H₂molar fraction, is at least predominantly CH₄.

In some embodiments, the pumping arrangements 80 are operative to injectthe hydrogen-containing gas 8 at a pressure that is at least 500 PSIhigher than the current shut-in gas pressure at the wellbore 10. In someembodiments, the pumping arrangements 90 are operative to inject thehydrogen-containing gas 8 at a pressure that is no more than 100 PSIless than a maximum wellhead pressure of the gas-recovery process of thereservoir 35, PRESSURE_(MAX). In some embodiments, the pumpingarrangements 90 are operative to inject the hydrogen-containing gas 8 ata pressure that is no more than 50 PSI less than PRESSURE_(MAX).

In some embodiments, the system 400 additionally includes surfacegeophysical-monitoring equipment for determining whether hydraulicfractures, e.g., one or more hydraulic fractures, are being extended bythe hydrogen injection. Suitable examples of surfacegeophysical-monitoring equipment include microseismic arrays andtiltmeters.

Referring now to FIG. 58A, a method is disclosed for storing andrecovering a hydrogen gas in a kerogen-rich unconventional gasreservoir. As illustrated by the flowchart in FIG. 58A, the methodcomprises Steps S311, S312, S313, S314, and S315, all of which arediscussed in the following paragraphs. A suitable system for use inperforming the method is the system 400 described above in connectionwith FIGS. 56 and 57 .

Step S311

Step S311 includes injecting a fracturing fluid through a horizontalwellbore into the geological formation to cause fracturing within thegeological formation. Arrangements for injecting a fracturing fluid intoa geological formation are illustrated schematically in FIG. 48 . Ageological formation 30, shown in accordance with the descriptionhereinabove of the second stage between Time=T₀ and Time=T₁, includes anorganic-rich shale deposit (also called a shale formation). Hydraulicfracturing equipment 70 is disposed at a wellhead 18. The wellhead 18 islocated at a wellpad 19 and is in fluid communication with anunconventional gas reservoir 35 located within the shale formation 30,which in the non-limiting example of FIG. 48 is below the water table27.

Step S312

Step S312 includes recovering a methane-containing gas 5 through thewellbore. Referring to FIG. 50 , gas-recovery activity at the wellhead18 is illustrated during the third stage of the timeline of FIG. 46 ,i.e., between Time=T₁ and Time=T₂. As indicated by directional arrow202, natural gas 5 is recovered through the wellbore 10 from thereservoir 35, including from the hydraulic fractures 32, and processedby gas recovery equipment 80 which is in fluid communication with thewellbore 10 at the wellhead 18. Recovery of the gas 5 reaches a maximumpressure PRESSURE_(MAX) after a short period (weeks or months) after gasrecovery begins, and declines thereafter.

Step S313

Step S313 includes projecting an H₂ molar fraction χ(H₂)_(RES)(T_(RES))of a hydrogen-containing gas recovered from the unconventional gasreservoir 35 at each of a plurality of corresponding reservoir pressuresPRESSURE_(RES)(T_(RES)) at respective reservoir times T_(RES).

The projecting is done on the basis of H₂ molar fraction valuesχ(H₂)_(CS) measured in gas recovered from a core sample in a core-samplechamber (or, equivalently, core-sample holder), e.g., in a laboratory.The core sample is taken from the unconventional reservoir 35, akerogen-rich geological formation, in which hydrogen is to be stored. Insome embodiments, the core sample is taken from or near a specific well11 of interest.

According to embodiments, Step S313 is performed by carrying out twosub-steps S313A and S313B, which are illustrated in the flowchart ofFIG. 58B:

Step S313A: sampling a recovered hydrogen-containing gas from agas-reservoir core sample held in the core-sample holder, to determine aplurality of core-sample value-pairs—an H₂ molar fraction valueχ(H₂)_(CS)(T_(CS)) and a respective core-sample pressure valuePRESSURE_(CS)(T_(CS))—for respective core-sample times T_(CS).

The laboratory apparatus 500 of FIGS. 51A-51B can also be used forperforming Step S313A.

In some embodiments, Step S313A includes introducing ahydrogen-containing gas for which an H₂ molar fraction χ(H₂) is known,into a core-sample holder 511. As discussed in the following paragraphs,the hydrogen-containing gas is introduced into the core-sample holder511 at a sampling point 1990 representing an off-gassing time T_(CS)(unless a different re-saturation pressure is used, in which caseadjustments can be made to the calculation, e.g., based on core-samplepressures PRESSURE_(CS).

An H₂ molar fraction χ(H₂)_(CS) corresponds to a pressure PRESSURE_(CS)in the core-sample holder at any time T_(CS). T_(CS) represents, forexample, how much time has elapsed since the beginning of off-gassing ofnatural gas by the core sample in a particular off-gassing session inthe core-sample chamber. An off-gassing session of the core sample canbe brought about through different procedures. For any of suchprocedures, the first off-gassing session is managed as follows: Becausea core sample taken from the unconventional gas reservoir is mostlydepleted of natural gas by the time it reaches the lab, it isre-saturated with natural gas, e.g., to reservoir pressure, and allowedto equilibrate. The natural gas is then allowed to produce until a firstsampling point e.g., point 1990 ₁ in FIG. 59 , which shows severalsampling points 1990 at various core-sample points of time T_(CS).Hydrogen gas is then injected back up to the initial reservoir pressure,or other selected initial core-sample pressure. H₂ gas is recovered fromthe core sample, and the H₂ fraction is measured, producing a‘core-sample value pair’ for each point 1990, the value pair including acore-sample pressure PRESSURE_(CS)(T_(CS)) and an H₂ molar fractionχ(H₂)_(CS)(T_(CS)).

According to a first exemplary procedure, following the first sampling,the hydrogen and residual natural gas are evacuated from the coresample, e.g., by lowering the pressure to atmospheric pressure,evacuating the core sample under vacuum, and raising the temperatureuntil all degassing stops. At this stage, the same core sample isre-saturated with natural gas up to the reservoir pressure, and thegeneral process repeats for the next H₂ injection and sampling.

According to a second exemplary procedure, a new core sample, e.g., onetaken from the unconventional gas reservoir adjacent to the first coresample, can be used for a subsequent H₂ injection at a later samplingpoint 1990. This alternative may be quicker than fully desaturating asingle core sample many times, but involves taking multiple core samplesfrom the unconventional gas reservoir 35.

Either of the two procedures can be repeated until a hydrogen-puritytrigger is reached by a measured or calculated value ofχ(H₂)_(CS)(T_(CS)). In embodiments, it can be preferable to re-saturatethe core sample with natural gas to the same pressure each time for easeof tracking, i.e., so that an off-gassing time T_(CS) of one cycle iscomparable to an off-gassing time T_(CS) of another cycle. In some casesthis is not necessary if the new pressure is higher than the intendedsampling pressure. In such cases, adjustments to the procedure can bemade based on comparing core-sample pressures PRESSURE_(CS) withoutdepending on the corresponding times T_(CS).

Both the H₂ molar fraction χ(H₂)_(CS)(T_(CS)) and thePRESSURE_(CS)(T_(CS)) are measured at each time T_(CS). When anH₂-purity trigger criterion is reached, e.g., a desired value of H₂purity for hydrogen to be recovered from storage in the reservoir 35,the corresponding core-sample pressure value PRESSURE_(CS) for the sametime T_(CS) is used for setting the ‘given’ reservoir pressurePRESSURE_(RES).

FIG. 59 illustrates a non-limiting example of a periodic samplingregime. FIG. 59 shows a series of points 1990 along the x-axis, whichrepresents time T_(CS), in hours, since the beginning of off-gassing ofa given core sample 550. As described earlier, each point 1990represents a different off-gassing session, whether of the same coresample 550 or of a substitute core sample used, e.g., to save the timeof completely desaturating the previous one. The y-axis representsvalues of hydrogen purity, i.e., (H₂ molar fraction, χ(H₂)_(CS), in therecovered hydrogen for each T_(CS) value. A hydrogen-purity triggerpoint 2005 is the specific point (T_(CS) value) 1990 at which themeasured/calculated H₂ molar fraction χ(H₂)_(CS) reaches a predeterminedtrigger criterion.

Step S313B: matching PRESSURE_(RES)(T_(RES)) values with respectivePRESSURE_(CS)(T_(CS)) values, to project χ(H₂)_(RES)(T_(RES)) valuesbased on χ(H₂)_(CS)(T_(CS)) values corresponding to the matchedrespective PRESSURE_(CS)(T_(CS)) values.

In Step S313A, both the hydrogen-purity value χ(H₂)_(CS)(T_(CS)) and thePRESSURE_(CS)(T_(CS)) are measured at each time T_(CS). When ahydrogen-purity trigger criterion is reached, e.g., a desired value ofhydrogen-purity value χ(H₂)_(CS), the corresponding core-sample pressurevalue PRESSURE_(CS) for the same time T_(CS) is used for setting the‘given’ reservoir pressure PRESSURE_(RES). Thus, measuring the reservoirpressure PRESSURE_(RES)(T_(RES)) at the reservoir at a time T_(RES)indicates that the H₂ molar fraction χ(H₂)_(RES)(T_(RES)) in thereservoir at the time T_(RES) corresponds to reaching thehydrogen-purity trigger criterion in the reservoir. The nomenclatureT_(RES) is introduced to differentiate elapsed time of gas recovery inthe reservoir (T_(RES)) from elapsed time of gas recovery from a coresample (T_(CS)), e.g., in a laboratory. The reservoir times T_(RES) canbe any time during the second stage, i.e., recovery ofmethane-containing gas 5 from the reservoir 35. T_(RES) can be measured,for example, as the time elapsed from the beginning of gas recovery atTime=T₁, which can be at the beginning of Step S312.

We now refer to FIGS. 59, 60, and 61 . These figures, when takentogether, can be used to illustrate the process of Step S313B. FIG. 59 ,as mentioned previously, illustrates the identification of ahydrogen-purity trigger point 2005 in the core-sample laboratory 500.The hydrogen-purity trigger point 2005 corresponds to a core-samplevalue pair for the respective core-sample time T_(CS) of hydrogen-puritytrigger point 2005.

As shown in FIG. 60 , The core-sample pair for the hydrogen-puritytrigger point 2005 at time T_(CS)=n corresponds to a core samplepressure of PRESSURE_(CS)(T_(CS)=n) and a hydrogen-purity valueχ(H₂)_(CS)(T_(CS)=n), which matches (or exceeds) the hydrogen-puritytrigger value.

In the reservoir 35, as shown in FIG. 61 , the reservoir pressurePRESSURE_(RES)(T_(RES)) is monitored, and at time T_(RES)=m, thereservoir pressure PRESSURE_(RES)(T_(RES)=m) matches the core samplepressure PRESSURE_(CS)(T_(CS)=n) of hydrogen-purity trigger point 2005of FIG. 60 . At the point where the pressures match, as indicated byT_(RES) point 2006 at T_(RES)=m, the reservoir hydrogen-purity valueχ(H₂)_(RES)(T_(RES)=m), equals the hydrogen-purity trigger valueχ(H₂)_(CS)(T_(CS)=n), i.e., the core-sample hydrogen-purity valuecorresponding to the hydrogen-purity trigger value 2005 of FIG. 60 .

Step S314

Step S314 includes injecting hydrogen gas through the wellbore 10according to an isotopic-signature trigger criterion, based uponhydrogen-purity value χ(H₂)_(RES)(T_(RES)=m) projected in Step S313.According to the method, it can be desirable to initiate injection ofhydrogen into a partially-depleted well at T_(RES)=m, corresponding tothe isotope-trigger point 2006 of FIG. 61 .

Step S314 takes place during the fourth stage of the timeline, betweenTime=T₂ and Time=T₃. As shown in the example of FIG. 56 , whereinjection of the hydrogen 8 is represented schematically by thedirectional arrow 203, hydrogen-gas-pumping arrangements 90 are providedin fluid communication with the reservoir 35 via wellbore 10. Inembodiments, the reservoir 35 and wellbore 10 are the same reservoir 35and wellbore 10 as in FIGS. 48 and 50 .

The skilled artisan will understand that the transition from the thirdstage of recovering methane to the fourth stage of injecting hydrogen atTime=T₂ can involve one or more preparatory steps performed betweenSteps S313 and S314 of the method. For example, it can be desirable toclose valves at the surface to cause pressure in the reservoir 35 toreach an equilibrium pressure. This can include closing the valves atthe surface to end gas recovery, and allowing time for the wellheadpressure to increase from a flowing wellhead pressure to a shut-inwellhead pressure. Over a period of weeks the shut-in wellhead pressurerises to an equilibrium pressure that is approximately equal toreservoir pressure.

The injection of the hydrogen gas 8, e.g., pure H₂, or ahydrogen-containing gas that includes at least 99% H₂ or at least 98%H₂, or at least 97% H₂, or at least 96% H₂, or at least 95% H₂, is at apressure higher than the current gas pressure at the wellhead 18, e.g.,the shut-in wellhead pressure at a stabilized reservoir-equilibriumpressure, so as to ensure that the hydrogen gas 8 propagates throughoutthe well, i.e., including the hydraulic fractures 32 and natural cracks.In some embodiments, the injection of hydrogen gas is at a pressure thatis at least 100 PSI higher than the current shut-in gas pressure at thewellbore 10 or at least 200 PSI higher, or at least 300 PSI higher, orat least 400 PSI higher, or at least 500 psi higher, or at least 800 PSIhigher. In embodiments, the initial injecting of the hydrogen gas 8 isat a pressure below the maximum gas-recovery pressure PRESSURE_(MAX) ofStep S302, or 50 or more PSI lower than PRESSURE_(MAX), or 100 or morePSI lower than PRESSURE_(MAX), or 200 or more PSI lower thanPRESSURE_(MAX). In embodiments, the initial injecting of the hydrogengas 8 is at a pressure below a hydrogen fracture extension pressureH₂FRAC_(EXT) at which the injection of the hydrogen gas 8 would causeextension of the existing fractures, including those propagated duringthe hydraulic fracturing of Step S301. The hydrogen fracture extensionpressure H₂FRAC_(EXT) is different than the FRAC_(EXT) of fracturingfluid discussed in Step S301 because of the weight of the hydrauliccolumn and the fluid friction. In some embodiments, H₂FRAC_(EXT) can becomputed from FRAC_(EXT), e.g., to act as a pressure limit duringhydrogen injection. In other embodiments, H₂FRAC_(EXT) can be measuredusing a diagnostic fracture injection test (DFIT), or it can be measuredby microseismic monitoring.

In embodiments, the injection of hydrogen gas 8 is at a pressure that isnot higher than the hydrogen-injection fracture extension pressureH₂FRAC_(EXT). Inter alia, this limitation is useful for avoiding, atleast partly, damage outside the wellbore 10 and the extension andbroadening of the existing hydraulic fractures 32, for example toprevent the release of additional free methane in and from the newlyexpanded fractures which affects the hydrogen purity during hydrogenproduction, and to prevent hydrogen loss to the formation. In someembodiments, the injecting of the hydrogen gas 8 is at a pressure thatis at least 200 PSI or at least 500 PSI less than H₂FRAC_(EXT). In someembodiments, the initial injecting of the hydrogen gas 8 is at apressure just below H₂FRAC_(EXT). In an example, the injecting of thehydrogen gas includes injecting the hydrogen gas at a pressure that is100 PSI less than H₂FRAC_(EXT). In some embodiments, surface geophysicalmonitoring, i.e., geophysical monitoring of the geological structurefrom the surface, is performed during hydrogen injection to determinewhether hydraulic fractures 32 are being extended by the hydrogeninjection. According to non-limiting examples, surface geophysicalmonitoring can include the use of surface geophysical monitoringequipment 95 such as microseismic arrays or tiltmeters. Gas phasetracers may also be added to the injected hydrogen 8 to see whetherthere is any communication of the hydrogen with adjacent productionwells on the wellhead. Suitable gas phase tracers are tritiated hydrogensuch as HT or T₂ in the range of 3 to 30×10{circumflex over ( )}10Becquerel (Bq) that may be detected at extremely low concentrations innearby production wells. According to a non-limiting example, atracer-gas facility 96 for adding a gas-phase tracer to the injectedhydrogen gas 8 is provided at or near the wellhead 10.

According to embodiments, the injection of the hydrogen gas of Step S314is initiated responsively to—and contingent upon—a determination, basedon the results of Step S313, that a hydrogen-purity value has reached aprojected trigger criterion for triggering a transition of theunconventional reservoir 35 from recovering the methane-containing gas 5to injecting a hydrogen gas 8.

Step S315

Step S315 includes recovering stored hydrogen gas 8 through the wellbore10, during the fifth stage of the timeline, between Time=T₃ and Time=T₄.As shown in the example of FIG. 55 , where recovery of thehydrogen-containing gas 8 is represented schematically by thedirectional arrow 204, hydrogen-gas-recovery equipment 80 is provided influid communication with the reservoir 35 via wellbore 10. Inembodiments, the reservoir 35 and wellbore 10 are the same reservoir 35and wellbore 10 as in FIGS. 48, 50 and 54 . The recoveredhydrogen-containing gas 8 can include, as illustrated schematically inFIG. 56 , bulk-phase H₂ in hydraulic fractures, H₂ in kerogen porespaces, H₂ adsorbed on kerogen surfaces, H₂ dissolved in kerogen, and/orbulk-phase H₂ contained in the non-organic pores or adsorbed on clays ofthe matrix of the geological formation 30.

According to the method, the recovered hydrogen-containing gas 8 has anH₂ molar fraction of at least 85%. The H₂ molar fraction of therecovered gas can be directly impacted by the selection of the reservoirin the first stage, e.g., selection of a kerogen-rich reservoir, and/orselection of a kerogen-rich reservoir with low permeability, as theterms have been defined herein. The H₂ molar fraction of the recoveredgas can be directly impacted by the selection of a flow-rate triggercriterion FLOW_(TRIGGER) with respect to the current flow rateFLOW_(CURRENT) of natural gas for initiating the injection of hydrogengas into the reservoir to begin the fourth stage. In embodiments,FLOW_(TRIGGER) is chosen to correspond to a state of the reservoir inwhich pore methane and kerogen-adsorbed methane is largely alreadyrecovered, such that the hydrogen gas replaces the methane in thefaster-recovery locations of the shale formation. The proper selectionof a FLOW_(TRIGGER) in terms of the timing of the initiating can lead toavoiding significant contamination of the H₂ by CH₄ in the pore spacesor desorbed from kerogen surfaces, and thus the recovered hydrogen canbe of higher purity, where purity refers to the H₂ molar fraction of therecovered gas. In various examples, the purity is at least 85%, or atleast 86%, or at least 87%, or at least 88%, or at least 89%, or atleast 90%, or at least 91%, or at least 92%, or at least 93%, or atleast 94%, or at least 95%, or at least 96%, or at least 97%, or atleast 98%, or at least 99%. In embodiments, the remainder of the gas,i.e., after subtracting the H₂ molar fraction, is at least predominantlyCH₄.

In some embodiments, not all the steps S311, S312, S313, S314, S315 ofthe method, as well as respective sub-steps, are performed.

Referring now to FIG. 62 , a method is disclosed for projecting anisotope ratio I-RATIO_(RES) respective of one or more molecularcomponents in a methane-containing gas recovered from a kerogen-richunconventional gas reservoir. As illustrated by the flowchart in FIG. 62, the method comprises Steps S321, S322, S323, S324, and S325, which arediscussed in the following paragraphs.

The laboratory apparatus 500 of FIGS. 51A-51B can be used for performingSteps S321, S322, S323, and S324.

Step S321: receiving a core sample obtained from a gas reservoir 35 in acore-sample holder 511. In an exemplary procedure, the core sample 550is first dried and weighed, then placed in the temperature-controlledcore sample holder 511. The core sample 550 delivered from theunconventional gas reservoir 35 is mostly depleted of natural gas by thetime it reaches the lab. In the lab, it must be re-saturated withnatural gas at a reservoir pressure and allowed to equilibrate. In anexample, the core sample 550 is re-saturated to an initial reservoirpressure of the reservoir 35 from which it is taken. In another example,the core sample 550 is re-saturated to the PRESSURE_(RES) of thereservoir 35 at the time that the core sample 550 was taken. In anotherexample, the core sample 550 is re-saturated to a pressure of thereservoir 35 at the time of the re-saturating in the core-sample holder511. In embodiments, it can be desirable for the pressure of there-saturation in the core-sample holder 511 to match a relevant pressurein the reservoir, while in other embodiments, arithmetic adjustments canbe made to calculations of Step S323 to overcome any discrepancy betweenan initial core-sample holder pressure PRESSURE_(CS) and an unmatchedreservoir pressure PRESSURE_(RES).

Step S322: introducing into the core-sample holder 511, amethane-containing gas for which an isotope ratio I-RATIO is known.

Examples of suitable isotope ratio values I-RATIO_(RES) include, and notexhaustively: a δ(¹³C) isotopic signature based on a ratio of ¹³C to ¹²C(or vice versa), and an isotopic-signature trigger criterion based on adeuterium-isotope ratio of a hydrocarbon-molecule component found in themethane containing gas. Suitable examples of a hydrocarbon-moleculecomponent include, and not exhaustively: methane (CH₄), where theisotopic-signature trigger criterion relates to monodeuterated methane:CH₃D/CH₄ or CH₃D/(CH₄+CH₃D); ethane (C₂H₆), where the isotopic-signaturetrigger criterion relates to monodeuterated ethane: C₂H₅D/C₂H₆ orC₂H₅D/(C₂H₆+C₂H₅D); propane (CHs), where the isotopic-signature triggercriterion relates to monodeuterated propane: C₃H₇D/C₃H₈ orC₃H₇D/(C₃H₈+C₃H₇D); butane (C₄H₁₀), where the isotopic-signature triggercriterion relates to monodeuterated butane: C₄H₉D/C₄H₁₀ orC₄H₉D/(C₄H₁₀+C₄H₉D); and pentane (C₅H₁₂), where the isotopic-signaturetrigger criterion relates to monodeuterated pentane: C₅H₁₁D/C₅H₁₂ orC₅H₁₁D/(C₅H₁₂+C₅H₁₁D). Collectively, methane, ethane, propane, butane,and pentane are members of the C1-C5 alkane group, and monodeuteratedmethane, monodeuterated ethane, monodeuterated propane, monodeuteratedbutane and monodeuterated pentane are members of the monodeuteratedC1-C5 alkane group.

The introducing includes regulating an internal gas pressure of thecore-sample holder to an initial core-sample pressurePRESSURE_(CS-INIT). In the non-limiting example of FIGS. 51A-B, twogases are provided for testing: He 522 and CH₄ 523, although in someother exemplary laboratory setups (not shown) other gases such as ethane(C₂H₆), propane (C₃H₈), butane (C₄H₁₀) or pentane (C₅H₁₂) are used inthe same manner as described here for CH₄, mutatis mutandis. The CH₄ gas523 (for example) can have a known (i.e., measured)¹³C/¹²C isotopicratio and/or a measured CH₃D/CH₄ isotopic ratio (adeuterated-to-non-deuterated methane ratio).

Step S323 periodically sample a gas mixture produced by the core samplein the core-sample holder at a core-sample pressurePRESSURE_(CS)(T_(CS)). The periodicity of the sampling need not beconstant during the off-gassing process. Any number or timing ofsampling times T_(CS) may be selected. In an exemplary analyticalprocedure, after pressure in the core-sample holder 511 is brought to apredetermined pressure that matches the initial pressure in theconventional gas reservoir 35 from which the core sample 550 was taken,the core sample is sealed in by the shutoff valve 525 and allowed toequilibrate with the methane gas 523. After equilibration, theoff-gassing core sample is then allowed to produce gas through the PCV508. Sampling (and analysis) of the gas produced in the core sampleholder 511 of the lab setup 500 of FIGS. 51A-B as required for thesampling to be carried out periodically and at different pressures, forexample with gas sampling cylinders 565.

Step S324 determine a core-sample isotope ratio I-RATIO_(CS)(T_(CS)) ofthe sampled gas mixture for each periodic sampling at respective valuesof PRESSURE_(CS)(T_(CS)). A core-sample value-pair can be measuredand/or calculated for each respective core-sample time T_(CS), whereeach core-sample value-pair includes a core-sample isotope ratioI-RATIO_(CS)(T_(CS)) value and a respective core-sample pressure valuePRESSURE_(CS)(T_(CS)). The δ(¹³C) and/or the δ(CH₃D/CH₄)—or in otherexamples, δ(C₂HSD/C₂H₆) or δ(C₃H₇D/C₃H₈) isotope ratios in the gassampling cylinders are measured by gas chromatography and isotope ratiomass spectrometry 550.

Step S325 projecting a reservoir isotope ratio I-RATIO_(RES)(T_(RES))value for a gas recovered from the gas reservoir at a correspondingreservoir pressure PRESSURE_(RES)(T_(RES)) at respective reservoir timesT_(RES), by using a recorded plurality of core-sample value pairs eachincluding a I-RATIO_(CS)(T_(CS)) value and a correspondingPRESSURE_(CS)(T_(CS)) value

In some embodiments, PRESSURE_(CS-INIT) equals PRESSURE_(RES-INIT), andthe projecting includes projecting a I-RATIO_(RES)(T_(RES)) value asbeing equal to a I-RATIO_(CS)(T_(CS)) value of a given core-sample valuepair, for a corresponding reservoir pressure PRESSURE_(RES)(T_(RES))equal to a PRESSURE_(CS)(T_(CS)) value of the same given core-samplevalue pair. In some embodiments, PRESSURE_(CS-INIT) is not equal toPRESSURE_(RES-INIT), and the projecting includes adjusting a projectedvalue of I-RATIO_(RES)(T_(RES)) for a difference betweenPRESSURE_(CS-INIT) and PRESSURE_(RES-INIT).

In some embodiments, not all the steps S321, S322, S323, S324, and S325of the method are performed.

Referring now to FIG. 63 , a method is disclosed for projecting an H₂molar fraction χ(H₂)_(R) of a hydrogen-containing gas recovered fromstorage in a kerogen-rich unconventional gas reservoir. As illustratedby the flowchart in FIG. 63 , the method comprises Steps S331, S332,S333, and S334, which are discussed in the following paragraphs.

The laboratory apparatus 500 of FIGS. 51A-51B can be used for performingStep S331, S332, and S333.

Step S331: receiving a core sample obtained from a gas reservoir in acore-sample holder. In an exemplary procedure, the core sample 550 isfirst dried and weighed, then placed in the temperature-controlled coresample holder 511.

Step S332: periodically sampling a gas mixture comprising ahydrogen-containing gas produced by the core sample in the core-sampleholder at a core-sample pressure PRESSURE_(CS)(T_(CS)).

In some embodiments, Step S332 includes introducing ahydrogen-containing gas for which an H₂ molar fraction χ(H₂) is known,into a core-sample holder 511. As discussed in the following paragraphs,the hydrogen-containing gas is introduced into the core-sample holder511 at a sampling point representing a specific off-gassing time T_(CS).T_(CS) represents, for example, how much time has elapsed since thebeginning of off-gassing of natural gas by the core sample in aparticular off-gassing session in the core-sample chamber. Anoff-gassing session of the core sample can be brought about throughdifferent procedures.

For any of such procedures, the first off-gassing session is managed asfollows: Because a core sample taken from the unconventional gasreservoir is mostly depleted of natural gas by the time it reaches thelab, it is re-saturated with natural gas, e.g., to reservoir pressure,and allowed to equilibrate. The natural gas is then allowed to off-gasuntil a first sampling point at a first time T_(CS). Hydrogen gas isthen injected into the core-sample holder 511 back up to the initialreservoir pressure, or other selected initial core-sample pressure. Ahydrogen-containing gas is then recovered from the core sample, and theH₂ fraction of the recovered gas is measured.

According to a first exemplary procedure, following the first sampling,the hydrogen and residual natural gas are evacuated from the coresample, e.g., by lowering the pressure to atmospheric pressure,evacuating the core sample under vacuum, and raising the temperatureuntil all degassing stops. At this stage, the same core sample isre-saturated with natural gas up to the reservoir pressure, and thegeneral process repeats for the next H₂ injection and Step S332sampling.

According to a second exemplary procedure, a new core sample, e.g., onetaken from the unconventional gas reservoir adjacent to the first coresample, can be used for a subsequent H₂ injection at a later samplingpoint. This alternative may be quicker than fully desaturating a singlecore sample many times, but involves taking multiple core samples fromthe unconventional gas reservoir 35.

In embodiments, it can be preferable to re-saturate the core sample withnatural gas to the same pressure each time for ease of tracking, i.e.,so that an off-gassing time T_(CS) of one sampling ‘cycle’ is comparableto an off-gassing time T_(CS) of another sampling cycle. In some casesthis is not necessary if the new pressure is higher than the intendedsampling pressure. In such cases, adjustments to the procedure can bemade, e.g., based on comparing core-sample pressures PRESSURE_(CS)without depending on the corresponding times T_(CS).

Step S333: determining a core-sample H₂ molar fractionχ(H₂)_(CS)(T_(CS)) of the sampled gas mixture for each of a plurality ofsamplings. For each sampling in Step S333, a ‘core-sample value pair’ isproduced, the value pair including a core-sample pressurePRESSURE_(CS)(T_(CS)), and an H₂ molar fraction χ(H₂)_(CS)(T_(CS)).

Step S334 projecting a reservoir isotope ratio χ(H₂)_(RES)(T_(RES))value for a hydrogen-containing gas recovered from the reservoir at acorresponding reservoir pressure PRESSURE_(RES)(T_(RES)), by using arecorded plurality of core-sample value pairs each including aχ(H₂)_(CS)(T_(CS)) value and a corresponding PRESSURE_(CS)(T_(CS))value.

In some embodiments, PRESSURE_(CS-INIT) equals PRESSURE_(RES-INIT), andthe projecting includes projecting a χ(H₂)_(RES)(T_(RES)) value as beingequal to a χ(H₂)_(CS)(T_(CS)) value of a given core-sample value pair,for a corresponding reservoir pressure PRESSURE_(RES)(T_(RES)) equal toa PRESSURE_(CS)(T_(CS)) value of the same given core-sample value pair.In some embodiments, PRESSURE_(CS-INIT) is not equal toPRESSURE_(RES-INIT), and the projecting includes adjusting a projectedvalue of χ(H₂)_(RES)(T_(RES)) for a difference betweenPRESSURE_(CS-INIT) and PRESSURE_(RES-INIT).

In some embodiments, not all the steps S331, S332, S333, and S334 of themethod are performed.

Any of the method steps disclosed herein can be combined with any othermethod steps, any such combinations being within the scope of theembodiments. Any of the disclosed embodiments can be combined in anypractical manner. In any of the disclosed methods, not all of the stepsneed be performed. Any of the steps of any of the disclosed methods canbe combined in any way to create combinations not explicitly disclosedand any such combinations are within the scope of the invention.

Additional Discussion

Some presently-disclosed embodiments relate, inter alia, to thefollowing inventive concepts.

Inventive concept 1. A method of operating a kerogen-rich unconventionalgas reservoir characterized by there being multiplehydraulically-fractured wells drilled thereinto, the method comprising:a. recovering a methane-containing gas from a firsthydraulically-fractured well drilled into the gas reservoir; b.steam-methane reforming the recovered methane-containing gas to yield ahydrogen gas and an inorganic carbon-containing gas; c. injecting atleast a portion of the hydrogen gas into a secondhydraulically-fractured well drilled into the gas reservoir; and d.injecting at least a portion of the inorganic carbon-containing gas intoa third hydraulically-fractured well drilled into the gas reservoir.

Inventive concept 2. The method of Inventive concept 1, additionallycomprising: recovering, from the second hydraulically-fractured well, ahydrogen-containing gas having an H₂ molar fraction of at least 85%.

Inventive concept 3. The method of either one of Inventive concepts 1 or2, wherein the second hydraulically-fractured well is partially depletedby a methane-containing-gas recovery process characterized by (i) amaximum flow rate and (ii) a minimum flow rate that is not more than 20%of the maximum flow rate.

Inventive concept 4. The method of any one of the preceding Inventiveconcepts, wherein the third hydraulically-fractured well is partiallydepleted by a methane-containing-gas recovery process characterized by(i) a maximum flow rate and (ii) a minimum flow rate that is at least10% of the maximum flow rate.

Inventive concept 5. The method of any one of the preceding Inventiveconcepts, additionally comprising, after the injecting of at least aportion of the inorganic carbon-containing gas into the thirdhydraulically-fractured well: further recovering, from the thirdhydraulically-fractured well, a methane-containing gas.

Inventive concept 6. The method of any one of Inventive concepts 2 to 5,wherein the steam-methane reforming uses energy produced from a portionof the recovered hydrogen-containing gas.

Inventive concept 7. The method of Inventive concept 6, wherein at leasta portion of the produced energy is in the form of heat.

Inventive concept 8. The method of Inventive concept 7, wherein the heatis generated by combusting a gas mixture comprising hydrogen andmethane.

Inventive concept 9. The method of Inventive concept 8, wherein thecombusted gas mixture comprises a portion of the recovered hydrogen.

Inventive concept 10. The method of any one of Inventive concepts 2 to9, additionally comprising: generating electricity from a portion of therecovered hydrogen-containing gas.

Inventive concept 11. The method of Inventive concept 10, wherein theelectricity is generated using a gas turbine.

Inventive concept 12. The method of Inventive concept 10, wherein theelectricity is generated using a reciprocating engine.

Inventive concept 13. The method of Inventive concept 10, wherein theelectricity is generated using a fuel cell.

Inventive concept 14. The method of any one of Inventive concepts 10 to13, wherein a portion of the generated electricity is used in thesteam-methane reforming.

Inventive concept 15. The method of any one of Inventive concepts 10 to13, wherein a majority of the generated electricity is delivered to adistribution network of an electric utility.

Inventive concept 16. The method of any one of Inventive concepts 10 to15, wherein the electricity is generated from a gas mixture comprisingmethane and hydrogen.

Inventive concept 17. The method of any one of the preceding Inventiveconcepts, additionally including: performing surface geophysicalmonitoring to determine whether hydraulic fractures are being extendedby the injecting of the hydrogen gas or of the inorganiccarbon-containing gas.

Inventive concept 18. The method of any one of the preceding Inventiveconcepts, wherein the multiple hydraulically-fractured wells arenon-communicating and non-intersecting with each other.

Inventive concept 19. The method of any one of the preceding Inventiveconcepts, additionally including: employing a gas phase tracer to verifythat hydraulic fractures of a given hydraulically-fractured well drilledinto the gas reservoir do not extend into a fracture that is in fluidcommunication with a different hydraulically-fractured well drilled intothe gas reservoir.

Inventive concept 20. The method of any one of the preceding Inventiveconcepts, wherein the inorganic carbon-containing gas includes carbondioxide.

Inventive concept 21. The method of any one of the preceding Inventiveconcepts, wherein the inorganic carbon-containing gas includes carbonmonoxide.

Inventive concept 22. The method of any one of Inventive concepts 2 to21, wherein the recovered hydrogen-containing gas has an H₂ molarfraction of at least 90%.

Inventive concept 23. The method of any one of Inventive concepts 2 to21, wherein the recovered hydrogen-containing gas has an H₂ molarfraction of at least 95%.

Inventive concept 24. The method of any one of Inventive concepts 2 to21, wherein the recovered hydrogen-containing gas has an H₂ molarfraction of at least 97%.

Inventive concept 25. A method of operating a kerogen-richunconventional gas reservoir characterized by there being multiplehydraulically-fractured wells drilled thereinto, the method comprising:a. receiving a methane-containing gas; b. steam-methane reforming themethane-containing gas to yield a hydrogen gas and an inorganiccarbon-containing gas; c. injecting at least a portion of the hydrogengas into a first hydraulically-fractured well drilled into the gasreservoir; and d. injecting at least a portion of the inorganiccarbon-containing gas into a second hydraulically-fractured well drilledinto the gas reservoir.

Inventive concept 26. The method of Inventive concept 25, additionallycomprising: separating the yielded hydrogen gas from the yieldedinorganic carbon-containing gas.

Inventive concept 27. The method of either one of Inventive concepts 25or 26, additionally comprising: recovering, from the firsthydraulically-fractured well, a hydrogen-containing gas having an H₂molar fraction of at least 85%.

Inventive concept 28. The method of any one of Inventive concepts 25 to27, wherein the first hydraulically-fractured well is partially depletedby a methane-containing-gas recovery process characterized by (i) amaximum flow rate and (ii) a minimum flow rate that is not more than 20%of the maximum flow rate.

Inventive concept 29. The method of any one of Inventive concepts 25 to28, wherein the second hydraulically-fractured well is partiallydepleted by a methane-containing-gas recovery process characterized by(i) a maximum flow rate and (ii) a minimum flow rate that is at least10% of the maximum flow rate.

Inventive concept 30. The method of any one of Inventive concepts 25 to29, additionally comprising, after the injecting of at least a portionof the inorganic carbon-containing gas into the secondhydraulically-fractured well: further recovering, from the secondhydraulically-fractured well, a methane-containing gas.

Inventive concept 31. The method of any one of Inventive concepts 27 to30, wherein the steam-methane reforming uses energy produced from aportion of the recovered hydrogen-containing gas.

Inventive concept 32. The method of Inventive concept 31, wherein aportion of the produced energy is in the form of heat.

Inventive concept 33. The method of Inventive concept 32, wherein theheat is generated by a combusting a gas mixture comprising methane andhydrogen.

Inventive concept 34. The method of Inventive concept 33, wherein thecombusted gas mixture comprises a portion of the recovered hydrogen.

Inventive concept 35. The method of any one of Inventive concepts 27 to34, additionally comprising: generating electricity from a portion ofthe recovered hydrogen-containing gas.

Inventive concept 36. The method of Inventive concept 35, wherein theelectricity is generated using a gas turbine.

Inventive concept 37. The method of Inventive concept 35, wherein theelectricity is generated using a reciprocating engine.

Inventive concept 38. The method of Inventive concept 35, wherein theelectricity is generated using a fuel cell.

Inventive concept 39. The method of any one of Inventive concepts 35 to38, wherein a portion of the generated electricity is used in thesteam-methane reforming.

Inventive concept 40. The method of any one of Inventive concepts 35 to38, wherein a majority of the generated electricity is delivered to adistribution network of an electric utility.

Inventive concept 41. The method of any one of Inventive concepts 33 to40, wherein the electricity is generated from a gas mixture comprisingmethane and hydrogen.

Inventive concept 42. The method of any one of Inventive concepts 25 to41, additionally including: performing surface geophysical monitoring todetermine whether hydraulic fractures are being extended by theinjecting of the hydrogen gas or of the inorganic carbon-containing gas.

Inventive concept 43. The method of any one of Inventive concepts 25 to42, wherein the multiple hydraulically-fractured wells arenon-communicating and non-intersecting with each other.

Inventive concept 44. The method of any one of Inventive concepts 25 to43, additionally including: employing a gas phase tracer to verify thathydraulic fractures of a given hydraulically-fractured well drilled intothe gas reservoir do not extend into a fracture that is in fluidcommunication with a different hydraulically-fractured well drilled intothe gas reservoir.

Inventive concept 45. The method of any one of Inventive concepts 25 to44, wherein the inorganic carbon-containing gas includes carbon dioxide.

Inventive concept 46. The method of any one of Inventive concepts 25 to44, wherein the inorganic carbon-containing gas includes carbonmonoxide.

Inventive concept 47. The method of any one of Inventive concepts 27 to46, wherein the recovered hydrogen-containing gas has an H₂ molarfraction of at least 90%.

Inventive concept 48. The method of any one of Inventive concepts 27 to46, wherein the recovered hydrogen-containing gas has an H₂ molarfraction of at least 95%.

Inventive concept 49. The method of any one of Inventive concepts 27 to46, wherein the recovered hydrogen-containing gas has an H₂ molarfraction of at least 97%.

Inventive concept 50. The method of any one of Inventive concepts 25 to49, wherein the received methane-containing gas is recovered from athird hydraulically-fractured well drilled into the gas reservoir.

Inventive concept 51. The method of any one of Inventive concepts 25 to50, wherein the received methane-containing gas is received from apipeline.

Inventive concept 52. A method of operating a kerogen-richunconventional gas reservoir characterized by there being multiplehydraulically-fractured wells drilled thereinto by multiplehydraulically-fractured wells, the method comprising: a. receiving amethane-containing gas; b. steam-methane reforming themethane-containing gas to yield a hydrogen gas and an inorganiccarbon-containing gas; c. injecting at least a portion of the hydrogengas into a first hydraulically-fractured well drilled into the gasreservoir; d. injecting at least a portion of the inorganiccarbon-containing gas into a second hydraulically-fractured well drilledinto the gas reservoir; e. recovering, from the firsthydraulically-fractured well, a hydrogen-containing gas having an H₂molar fraction of at least 85%; and f. generating electricity from atleast a portion of the recovered hydrogen-containing gas.

Inventive concept 53. The method of Inventive concept 52, wherein atleast a portion of the received methane-containing gas is recovered froma third hydraulically-fractured well drilled into the gas reservoir.

Inventive concept 54. The method of either one of Inventive concepts 52or 53, wherein at least a portion of the received methane-containing gasis recovered from the second hydraulically-fractured well after theinjecting of the at least a portion of the inorganic carbon-containinggas into the second hydraulically-fractured well.

Inventive concept 55. The method of any one of Inventive concepts 52 to54, wherein at least a portion of the received methane-containing gas isreceived from a pipeline.

Inventive concept 56. The method of any one of Inventive concepts 52 to55, wherein the steam-methane reforming uses energy produced from aportion of the recovered hydrogen-containing gas.

Inventive concept 57. The method of Inventive concept 56, wherein atleast a portion of the produced energy is in the form of heat.

Inventive concept 58. The method of Inventive concept 57, wherein theheat is generated by combusting a gas mixture comprising hydrogen andmethane.

Inventive concept 59. The method of Inventive concept 58, wherein thecombusted gas mixture comprises a portion of the recovered hydrogen.

Inventive concept 60. The method of any one of Inventive concepts 52 to59, wherein the electricity is generated using a gas turbine.

Inventive concept 61. The method of any one of Inventive concepts 52 to60, wherein the electricity is generated using a reciprocating engine.

Inventive concept 62. The method of any one of Inventive concepts 52 to61, wherein the electricity is generated using a fuel cell.

Inventive concept 63. The method of any one of Inventive concepts 52 to62, wherein a portion of the generated electricity is used in thesteam-methane reforming.

Inventive concept 64. The method of any one of Inventive concepts 52 to62, wherein a majority of the generated electricity is delivered to adistribution network of an electric utility.

Inventive concept 65. The method of any one of Inventive concepts 52 to64, wherein the electricity is generated from a gas mixture comprisingmethane and hydrogen.

Inventive concept 66. A system for producing, storing and subsequentlyrecovering a hydrogen-containing gas, the system comprising: a. asteam-methane reformer for receiving and steam-reforming amethane-containing gas to yield a hydrogen gas and an inorganiccarbon-containing gas; b. pumping arrangements for thehydrogen-containing gas, disposed in fluid communication with a firstpartially-depleted, hydraulically-fractured well drilled into akerogen-rich, unconventional reservoir of the methane-containing gas,and operative to inject the hydrogen gas through a respective horizontalwellbore into the first hydraulically-fractured well at a pressurehigher than a current gas pressure at the wellbore, the partialdepletion of the first hydraulically-fractured well being by amethane-containing-gas recovery process characterized by a maximum flowrate of FLOW_(MAX), and a minimum flow rate of FLOW_(MIN) that is atleast 10% of FLOW_(MAX) and not more than 20% of FLOW_(MAX); c. pumpingarrangements for the inorganic carbon-containing gas, disposed in fluidcommunication with a second partially-depleted, hydraulically-fracturedwell drilled into the kerogen-rich, unconventional reservoir, andoperative to inject the hydrogen gas through a respective horizontalwellbore into the second hydraulically-fractured well at a pressurehigher than a current gas pressure at the wellbore, the partialdepletion of the second hydraulically-fractured well being by amethane-containing-gas recovery process characterized by a maximum flowrate of FLOW_(MAX), and a minimum flow rate of FLOW_(MIN) that is atleast 10% of FLOW_(MAX) and not more than 30% of FLOW_(MAX); and d.gas-recovery equipment disposed in fluid communication with the firsthydraulically-fractured well and operative to recover a portion of thehydrogen-containing gas through the respective horizontal wellbore, therecovered portion of the hydrogen-containing gas having an H₂ molarfraction of at least 85%.

Inventive concept 67. The system of Inventive concept 66, additionallyincluding piping for delivering, to the steam-methane reformer,methane-containing gas recovered from a third partially-depleted,hydraulically-fractured well drilled into the kerogen-rich,unconventional reservoir.

Inventive concept 68. The system of either one of Inventive concepts 66or 67, additionally including an electrical generator arranged toreceive at least a portion of the recovered hydrogen-containing gas togenerate electricity therefrom.

Inventive concept 69. The system of Inventive concept 68, wherein theelectrical generator is also arranged to receive a least a portion ofthe yielded hydrogen gas from the steam-methane reformer.

Inventive concept 70. The system of any one of Inventive concepts 66 to69, additionally including a separator facility for separating hydrogengas from methane gas.

Inventive concept 71. The system of any one of Inventive conceptsInventive concept 66 to 70, additionally including a separator facilityfor separating hydrogen gas from an inorganic carbon-containing gas.

Inventive concept 72. The system of any one of Inventive concepts 66 to70, additionally including electricity transmission arrangements fordelivering electricity from the electrical generator to thesteam-methane reformer.

Inventive concept 73. The system of any one of Inventive concepts 66 to72, wherein the recovered portion of the hydrogen gas has an H₂ molarfraction of at least 90%.

Inventive concept 74. The system of any one of Inventive concepts 66 to72, wherein the recovered portion of the hydrogen gas has an H₂ molarfraction of at least 95%.

Inventive concept 75. The system of any one of Inventive concepts 66 to72, wherein the recovered portion of the hydrogen gas has an H₂ molarfraction of at least 97%.

Inventive concept 76. The system of any one of Inventive concepts 66 to75, wherein a kerogen concentration in the reservoir is at least 2% byvolume.

Inventive concept 77. The system of any one of Inventive concepts 66 to76, additionally including surface geophysical-monitoring equipment fordetermining whether hydraulic fractures are being extended by thehydrogen injection.

Inventive concept 78. The system of any one of Inventive concepts 66 to77, additionally including a tracer-gas facility for adding a gas-phasetracer to the injected hydrogen gas.

Inventive concept 79. The system of any one of Inventive concepts 66 to78, additionally including a blending facility operative to yield a gasmixture with a preset H₂-to-CH₄ ratio.

Inventive concept 80. The system of Inventive concept 79, wherein theblending facility is in fluid communication with a pipeline.

Inventive concept 81. The system of either one of Inventive concepts 79or 80, wherein the blending facility is in fluid communication with theelectricity generator.

Inventive concept 82. A method of storing hydrogen gas in a kerogen-richgeological formation, the method comprising: a. injecting a fracturingfluid through a horizontal wellbore into the geological formation tocause fracturing within the geological formation; b. recovering amethane-containing gas through the wellbore, the recoveringcharacterized by a maximum flow rate FLOW_(MAX); c. monitoring a currentflow rate FLOW_(CURRENT) of the recovered methane-containing gas overtime; d. responsively to and contingent upon the monitoredFLOW_(CURRENT) being equal to or less than a flow-rate trigger criterionFLOW_(TRIGGER), injecting a hydrogen gas through the wellbore into thegeological formation at a pressure higher than a current shut-in gaspressure at the wellbore; and e. recovering, through the wellbore, ahydrogen-containing gas having an H₂ molar fraction of at least 85%,wherein FLOW_(TRIGGER) is equal to at least 10% of FLOW_(MAX) and notmore than 20% of FLOW_(MAX).

Inventive concept 83. The method of Inventive concept 82, whereinFLOW_(TRIGGER) is equal to at least 10% of FLOW_(MAX) and not more than15% of FLOW_(MAX).

Inventive concept 84. The method of either one of Inventive concepts 82or 83, wherein FLOW_(TRIGGER) is selected based on a kerogenconcentration in the geological formation.

Inventive concept 85. The method of any one of Inventive concepts 82 to84, wherein FLOW_(TRIGGER) is selected based on a fluid flow regime ofthe geological formation.

Inventive concept 86. The method of Inventive concept 85 wherein thefluid flow regime of the geological formation is substantiallycharacterized by diffusional processes.

Inventive concept 87. The method of Inventive concept 86 wherein thefluid flow regime of the geological formation is substantially Knudsendiffusion.

Inventive concept 88. The method of any one of Inventive concepts 85 to87 wherein the fluid flow regime in the reservoir is monitored by adelta(C13) isotope ratio in the produced methane.

Inventive concept 89. The method of any one of Inventive concepts 82 to88, wherein (i) the recovering of the methane-containing gas isadditionally characterized by a maximum wellhead pressure ofPRESSURE_(MAX), and (ii) the injecting of the hydrogen gas includesinjecting the hydrogen gas at a pressure that is 100-or-more PSI lowerthan PRESSURE_(MAX).

Inventive concept 90. The method of any one of Inventive concepts 82 to89, wherein the injecting of the hydrogen gas includes injecting thehydrogen gas at a pressure that is at least 500 PSI higher than thecurrent shut-in gas pressure at the wellbore.

Inventive concept 91. The method of any one of Inventive concepts 82 to90, wherein the injecting of the hydrogen gas is at a pressure that isless than a calculated hydrogen fracture extension pressure H₂FRAC_(EXT)within the geological formation.

Inventive concept 92. The method of any one of Inventive concepts 82 to91, wherein surface geophysical monitoring is performed during hydrogeninjection to determine whether hydraulic fractures are being extended bythe hydrogen injection.

Inventive concept 93. The method of any one of Inventive concepts 82 to92, wherein the injecting of the hydrogen gas is at a pressure that isat least 500 PSI less than a calculated hydrogen fracture extensionpressure H₂FRAC_(EXT) at the wellhead.

Inventive concept 94. The method of any one of Inventive concepts 82 to93, wherein a gas phase tracer is used to determine whether hydraulicfractures extend into a fracture that is in fluid communication with asecond wellbore.

Inventive concept 95. The method of any one of Inventive concepts 82 to94, wherein the monitoring of the current flow rate FLOW_(CURRENT)includes determining the flow regime in the reservoir.

Inventive concept 96. The method of any one of Inventive concepts 82 to95, wherein the recovered hydrogen-containing gas has an H₂ molarfraction of at least 90%.

Inventive concept 97. The method of any one of Inventive concepts 82 to96, wherein the recovered hydrogen-containing gas has an H₂ molarfraction of at least 95%.

Inventive concept 98. The method of any one of Inventive concepts 82 to97, wherein the recovered hydrogen-containing gas has an H₂ molarfraction of at least 97%.

Inventive concept 99. The method of any one of Inventive concepts 82 to98, wherein the kerogen concentration of the kerogen-rich geologicalformation is at least 2% by volume.

Inventive concept 100. A method of storing and subsequently recovering ahydrogen gas, the method comprising: a. injecting the hydrogen gasthrough a horizontal wellbore into a hydraulically-fractured,kerogen-rich, and partially-depleted reservoir of a methane-containinggas, at a pressure higher than a current gas pressure at the wellbore,the partial depletion of the reservoir being by a methane-containing-gasrecovery process characterized by a maximum flow rate of FLOW_(MAX), anda minimum flow rate of FLOW_(MIN) that is at least 10% of FLOW_(MAX) andnot more than 20% of FLOW_(MAX); b. recovering a portion of the hydrogengas through the wellbore, the recovered portion of the hydrogen gashaving an H₂ molar fraction of at least 85%.

Inventive concept 101. The method of Inventive concept 100, whereinFLOW_(MIN) is equal to at least 10% of FLOW_(MAX) and not more than 15%of FLOW_(MAX).

Inventive concept 102. The method of either one of Inventive concepts100 or 101, additionally comprising a step, performed before theinjecting of the hydrogen gas, of selecting the reservoir based on akerogen concentration in the reservoir.

Inventive concept 103. The method of either one of Inventive concepts100 or 101, additionally comprising a step, performed before theinjecting of the hydrogen gas, of selecting the reservoir based on afluid flow regime of the reservoir.

Inventive concept 104. The method of Inventive concept 103 wherein thefluid flow regime of the geological formation is substantiallycharacterized by diffusional processes.

Inventive concept 105. The method of Inventive concept 104 wherein thefluid flow regime of the geological formation is substantially Knudsendiffusion.

Inventive concept 106. The method of any one of Inventive concepts 100to 105, wherein (i) the methane-containing-gas recovery process isadditionally characterized by a maximum wellhead pressure ofPRESSURE_(MAX), and (ii) the injecting of the hydrogen gas includesinjecting the hydrogen gas at a pressure that is 100-or-more PSI lessthan PRESSURE_(MAX).

Inventive concept 107. The method of any one of Inventive concepts 100to 106, wherein the injecting of the hydrogen gas includes injecting thehydrogen gas at a pressure that is at least 500 PSI higher than thecurrent shut-in gas pressure at the wellbore.

Inventive concept 108. The method of any one of Inventive concepts 100to 107 wherein the injecting of the hydrogen gas includes surfacegeophysical monitoring to verify that hydraulic fractures are not beingextended by the injecting.

Inventive concept 109. The method of any one of Inventive concepts 100to 108, wherein a gas phase tracer is used to verify that hydraulicfractures do not extend into a fracture that is in fluid communicationwith a second wellbore.

Inventive concept 110. The method of any one of Inventive concepts 100to 109, wherein the recovered portion of the hydrogen gas has an H₂molar fraction of at least 90%.

Inventive concept 111. The method of any one of Inventive concepts 100to 110, wherein the recovered portion of the hydrogen gas has an H₂molar fraction of at least 95%.

Inventive concept 112. The method of any one of Inventive concepts 100to 111, wherein the recovered portion of the hydrogen gas has an H₂molar fraction of at least 97%.

Inventive concept 113. The method of any one of Inventive concepts 100to 112, wherein the kerogen concentration in the reservoir is at least2% by volume.

Inventive concept 114. A system for storing and subsequently recoveringa hydrogen-containing gas, the system comprising: a. pumpingarrangements for hydrogen-containing gas, disposed in fluidcommunication with a hydraulically-fractured, kerogen-rich andpartially-depleted reservoir of a methane-containing gas and operativeto inject the hydrogen gas through a horizontal wellbore into thereservoir at a pressure higher than a current gas pressure at thewellbore, the partial depletion of the reservoir being by amethane-containing-gas recovery process characterized by a maximum flowrate of FLOW_(MAX), and a minimum flow rate of FLOW_(MIN) that is atleast 10% of FLOW_(MAX) and not more than 20% of FLOW_(MAX); and b.gas-recovery equipment disposed in fluid communication with thereservoir and operative to recover a portion of the hydrogen-containinggas through the wellbore, the recovered portion of thehydrogen-containing gas having an H₂ molar fraction of at least 85%.

Inventive concept 115. The system of Inventive concept 114, whereinFLOW_(MIN) is equal to at least 10% of FLOW_(MAX) and not more than 15%of FLOW_(MAX).

Inventive concept 116. The system of either one of Inventive concepts114 or 115, wherein the fluid flow regime of the geological formation issubstantially characterized by diffusional processes.

Inventive concept 117. The system of Inventive concept 116 wherein thefluid flow regime of the geological formation is substantially Knudsendiffusion.

Inventive concept 118. The system of any one of Inventive concepts 114to 117, wherein (i) the methane-containing-gas recovery process isadditionally characterized by a maximum wellhead pressure ofPRESSURE_(MAX), and (ii) the pumping arrangements are operative toinject the hydrogen-containing gas at a pressure that is 100-or-more PSIless than PRESSURE_(MAX).

Inventive concept 119. The system of any one of Inventive concepts 114to 118, wherein the pumping arrangements are operative to inject thehydrogen-containing gas at a pressure that is at least 500 PSI higherthan the current shut-in gas pressure at the wellbore.

Inventive concept 120. The system of any one of Inventive concepts 114to 119, additionally including surface geophysical-monitoring equipmentfor determining whether hydraulic fractures are being extended by thehydrogen injection.

Inventive concept 121. The system of any one of Inventive concepts 114to 120, additionally including a tracer-gas facility for adding agas-phase tracer to the injected hydrogen gas.

Inventive concept 122. The system of any one of Inventive concepts 114to 121, wherein the recovered portion of the hydrogen gas has an H₂molar fraction of at least 90%.

Inventive concept 123. The system of any one of Inventive concepts 114to 121, wherein the recovered portion of the hydrogen gas has an H₂molar fraction of at least 95%.

Inventive concept 124. The system of any one of Inventive concepts 114to 121, wherein the recovered portion of the hydrogen gas has an H₂molar fraction of at least 97%.

Inventive concept 125. The system of any one of Inventive concepts 114to 124, wherein a kerogen concentration in the reservoir is at least 2%by volume.

Inventive concept 126. A method of storing and subsequently recoveringhydrogen gas in a kerogen-rich unconventional gas reservoir, the methodcomprising: a. injecting a fracturing fluid through a horizontalwellbore into the geological formation to cause fracturing within thegas reservoir; b. recovering a methane-containing gas through thewellbore; c. monitoring an isotopic signature respective of at least onemolecular component of the recovered methane-containing gas; d.responsively to and contingent upon reaching an isotopic-signaturetrigger criterion based upon the monitored isotopic signature, injectinghydrogen gas through the wellbore into the geological formation at apressure higher than a shut-in gas pressure at a wellhead; and e.recovering, through the wellbore, a hydrogen-containing gas having an H₂molar fraction of at least 85%.

Inventive concept 127. The method of Inventive concept 126, wherein theisotopic signature is based upon an isotope ratio, and the isotopicratio is δ(¹³C).

Inventive concept 128. The method of Inventive concept 126, wherein theisotopic signature is based upon an isotope ratio having the formδ(C_(X)H_(Y-1)D/C_(X)H_(Y)).

Inventive concept 129. The method of any one of Inventive concepts 126to 128, wherein the at least one molecular component comprises methane.

Inventive concept 130. The method of any one of Inventive concepts 126to 128, wherein the at least one molecular component comprises ethane.

Inventive concept 131. The method any one of Inventive concepts 126 to128, wherein the at least one molecular component comprises propane.

Inventive concept 132. The method of any one of Inventive concepts 126to 128, wherein the at least one molecular component comprises butane.

Inventive concept 133. The method of any one of Inventive concepts 126to 128, wherein the at least one molecular component comprises pentane.

Inventive concept 134. The method of Inventive concept 126, wherein (i)the isotopic signature is based upon an isotope ratio, and the isotopicratio is of the form δ(C_(X)H_(Y-1)D/C_(A)H_(B)), (ii) C_(X)H_(Y-1)D isa monodeuterated molecule of a first hydrocarbon selected from ahydrocarbon group consisting of: methane, ethane, propane, butane andpentane hydrocarbon, and (iii) C_(A)H_(B) is a non-deuterated moleculeof a second hydrocarbon that is not the first hydrocarbon, selected fromthe hydrocarbon group.

Inventive concept 135. The method of Inventive concept 126, wherein (i)the isotopic signature has the form δ(EXP₁/EXP₂), (ii) EXP₁ is anexpression representing a monodeuterated multi-alkane sum of respectiveconcentrations of one or more of: monodeuterated ethane, monodeuteratedpropane, monodeuterated butane, and monodeuterated pentane, and (iii)EXP₂ is an expression representing a concentration of monodeuteratedmethane.

Inventive concept 136. The method of Inventive concept 126, wherein (i)the isotopic signature has the form δ(EXP₁/EXP₂), (ii) EXP₁ is anexpression representing a monodeuterated-methane concentration, and(iii) EXP₂ is an expression representing a respective concentration ofany one of: monodeuterated ethane, monodeuterated propane,monodeuterated butane, and monodeuterated pentane.

Inventive concept 137. The method of Inventive concept 126, wherein (i)the isotopic signature has the form δ(EXP₁/EXP₂), (ii) EXP₁ is anexpression representing respective concentrations of one or more membersof the monodeuterated C1-C5 alkane group consisting of monodeuteratedmethane, monodeuterated ethane, monodeuterated propane, monodeuteratedbutane, and monodeuterated pentane, and (iii) EXP₂ is an expressionrepresenting respective concentrations of one or more members of saidmonodeuterated C1-C5 alkane group with the exception of the one or moremembers represented in EXP₁.

Inventive concept 138. The method of Inventive concept 126, wherein (i)the isotopic signature has the form δ(EXP₁/EXP₂), (ii) EXP₁ is anexpression representing any member of the monodeuterated C1-C5 alkanegroup consisting of monodeuterated methane, monodeuterated ethane,monodeuterated propane, monodeuterated butane, and monodeuteratedpentane, and (iii) EXP₂ is an expression representing any other memberof said monodeuterated C1-C5 alkane group.

Inventive concept 139. The method of Inventive concept 126, wherein theisotopic signature is based upon a ratio of isotope ratios and has theform δ(¹³C)_(ALKANE1)/δ(¹³C)_(ALKANE2), where each of ALKANE1 andALKANE2 includes an alkane selected from an alkane group consisting of:methane, ethane, propane, butane and pentane.

Inventive concept 140. The method of Inventive concept 139, wherein atleast one of ALKANE1 and ALKANE2 includes an arithmetic combination ofmultiple alkanes selected from the alkane group.

Inventive concept 141. The method of any one of Inventive concepts 126to 140, wherein monitoring the isotopic signature includes detecting adecrease in the isotope ratio from an initial value to a minimum valueand, subsequently thereto, detecting an increase in the isotope ratio.

Inventive concept 142. The method of Inventive concept 141, whereinreaching the isotopic-signature-trigger criterion includes detecting anincrease in the isotope ratio in at least two successive samples of therecovered methane-containing gas.

Inventive concept 143. The method of any one of Inventive concepts 126to 142, wherein the injecting of the hydrogen gas is at a pressure thatis less than a calculated hydrogen fracture extension pressureH₂FRAC_(EXT) within the geological formation.

Inventive concept 144. The method of any one of Inventive concepts 126to 143, wherein surface geophysical monitoring is performed duringhydrogen injection to determine whether hydraulic fractures are beingextended by the hydrogen injection.

Inventive concept 145. The method of any one of Inventive concepts 126to 144, wherein a gas phase tracer is used to determine whetherhydraulic fractures extend into a fracture that is in fluidcommunication with a second wellbore.

Inventive concept 146. The method of any one of Inventive concepts 126to 145, wherein the recovered hydrogen-containing gas has an H₂ molarfraction of at least 90%.

Inventive concept 147. The method of any one of Inventive concepts 126to 146, wherein the recovered hydrogen-containing gas has an H₂ molarfraction of at least 95%.

Inventive concept 148. The method of any one of Inventive concepts 126to 147, wherein the recovered hydrogen-containing gas has an H₂ molarfraction of at least 97%.

Inventive concept 149. The method of any one of Inventive concepts 126to 148, wherein the kerogen concentration of the kerogen-rich geologicalformation is at least 2% by volume.

Inventive concept 150. A method of storing and subsequently recoveringhydrogen gas in a kerogen-rich, hydraulically-fractured unconventionalgas reservoir, the method comprising: a. sampling, at a plurality oftimes, a methane-containing gas recovered from the geological formationthrough a horizontal wellbore; b. determining, from each sampling, anisotopic signature of a molecular component in the sampledmethane-containing gas, the isotopic signature being based upon anisotope ratio; c. responsively to and contingent upon detecting anincrease in the isotopic signature of at least two successive samplings,injecting hydrogen gas through the wellbore into the geologicalformation at a pressure higher than a shut-in gas pressure; and d.recovering, through the wellbore, a hydrogen-containing gas having an H₂molar fraction of at least 85%.

151. The method of Inventive concept 150, wherein the isotope ratio isδ(¹³C).

Inventive concept 152. The method of Inventive concept 150, wherein theisotope ratio is of the form δ(C_(X)H_(Y-1)D/C_(X)H_(Y)).

Inventive concept 153. The method of any one of Inventive concepts 150to 152, wherein the molecular component comprises methane.

Inventive concept 154. The method of any one of Inventive concepts 150to 152, wherein the molecular component comprises ethane.

Inventive concept 155. The method any one of Inventive concepts 150 to152, wherein the molecular component comprises propane.

Inventive concept 156. The method of any one of Inventive concepts 150to 152, wherein the molecular component comprises butane.

Inventive concept 157. The method of any one of Inventive concepts 150to 152, wherein the molecular component comprises pentane.

Inventive concept 158. The method of Inventive concept 150, wherein (i)the isotopic signature is based upon an isotope ratio, and the isotopicratio is of the form δ(C_(X)H_(Y-1)D/C_(A)H_(B)), (ii) C_(X)H_(Y-1)D isa monodeuterated molecule of a first hydrocarbon selected from ahydrocarbon group consisting of: methane, ethane, propane, butane andpentane hydrocarbon, and (iii) C_(A)H_(B) is a non-deuterated moleculeof a second hydrocarbon that is not the first hydrocarbon, selected fromthe hydrocarbon group.

Inventive concept 159. The method of Inventive concept 150, wherein (i)the isotopic signature has the form δ(EXP₁/EXP₂), (ii) EXP₁ is anexpression representing a monodeuterated multi-alkane sum of respectiveconcentrations of one or more of: monodeuterated ethane, monodeuteratedpropane, monodeuterated butane, and monodeuterated pentane, and (iii)EXP₂ is an expression representing a concentration of monodeuteratedmethane.

Inventive concept 160. The method of Inventive concept 150, wherein (i)the isotopic signature has the form δ(EXP₁/EXP₂), (ii) EXP₁ is anexpression representing a monodeuterated-methane concentration, and(iii) EXP₂ is an expression representing a respective concentration ofany one of: monodeuterated ethane, monodeuterated propane,monodeuterated butane, and monodeuterated pentane.

Inventive concept 161. The method of Inventive concept 150, wherein (i)the isotopic signature has the form δ(EXP₁/EXP₂), (ii) EXP₁ is anexpression representing respective concentrations of one or more membersof the monodeuterated C1-C5 alkane group consisting of monodeuteratedmethane, monodeuterated ethane, monodeuterated propane, monodeuteratedbutane, and monodeuterated pentane, and (iii) EXP₂ is an expressionrepresenting respective concentrations of one or more members of saidmonodeuterated C1-C5 alkane group with the exception of the one or moremembers represented in EXP₁.

Inventive concept 162. The method of Inventive concept 150, wherein (i)the isotopic signature has the form δ(EXP₁/EXP₂), (ii) EXP₁ is anexpression representing any member of the monodeuterated C1-C5 alkanegroup consisting of monodeuterated methane, monodeuterated ethane,monodeuterated propane, monodeuterated butane, and monodeuteratedpentane, and EXP₂ is an expression representing any other member of saidmonodeuterated C1-C5 alkane group.

Inventive concept 163. The method of Inventive concept 150, wherein theisotopic signature is based upon a ratio of isotope ratios and has theform δ(¹³C)_(ALKANE1)/δ(¹³C)_(ALKANE2), where each of ALKANE1 andALKANE2 includes an alkane selected from an alkane group consisting of:methane, ethane, propane, butane and pentane.

Inventive concept 164. The method of Inventive concept 163, wherein atleast one of ALKANE1 and ALKANE2 includes an arithmetic combination ofmultiple alkanes selected from the alkane group.

Inventive concept 165. The method of any one of Inventive concepts 150to 164, wherein the injecting of the hydrogen gas is at a pressure thatis less than a calculated hydrogen fracture extension pressureH₂FRAC_(EXT) within the geological formation.

Inventive concept 166. The method of any one of Inventive concepts 150to 165 wherein the injecting of the hydrogen gas includes surfacegeophysical monitoring to determine whether hydraulic fractures arebeing extended by the injecting.

Inventive concept 167. The method of any one of Inventive concepts 150to 166, wherein a gas phase tracer is used to verify that hydraulicfractures do not extend into a fracture that is in fluid communicationwith a second wellbore.

Inventive concept 168. The method of any one of Inventive concepts 150to 167, wherein the recovered portion of the hydrogen gas has an H₂molar fraction of at least 90%.

Inventive concept 169. The method of any one of Inventive concepts 150to 168, wherein the recovered portion of the hydrogen gas has an H₂molar fraction of at least 95%.

Inventive concept 170. The method of any one of Inventive concepts 150to 169, wherein the recovered portion of the hydrogen gas has an H₂molar fraction of at least 97%.

Inventive concept 171. The method of any one of Inventive concepts 150to 170, wherein the kerogen concentration in the reservoir is at least2% by volume.

Inventive concept 172. A system for storing and subsequently recoveringa hydrogen-containing gas, the system comprising: a. pumpingarrangements for a hydrogen-containing gas, disposed in fluidcommunication with a hydraulically-fractured, kerogen-rich andpartially-depleted reservoir of a methane-containing gas and operativeto inject the hydrogen gas through a horizontal wellbore into thereservoir at a pressure higher than a current gas pressure wellhead at apressure higher than the shut-in gas pressure at a wellhead, the partialdepletion of the reservoir being by a methane-containing-gas recoveryprocess characterized by an initial isotope signature valueδ(MC)_(INITIAL), a minimum isotopic signature value δ(MC)_(MIN), and acurrent isotopic signature value δ(MC)_(CURRENT) greater thanδ(MC)_(MIN), wherein MC is a molecular component in the sampledmethane-containing gas and δ(MC) is based upon an isotope ratio of themolecular component MC of the methane-containing gas, and b.gas-recovery equipment disposed in fluid communication with thereservoir and operative to recover a portion of the hydrogen-containinggas through the wellbore, the recovered portion of thehydrogen-containing gas having an H₂ molar fraction of at least 85%.

Inventive concept 173. The system of Inventive concept 172, wherein theisotope ratio is δ(¹³C).

Inventive concept 174. The system of Inventive concept 172, wherein theisotope ratio is of the form δ(C_(X)H_(Y-1)D/C_(X)H_(Y)).

Inventive concept 175. The system of any one of Inventive concepts 172to 174, wherein the molecular component comprises methane.

Inventive concept 176. The system of any one of Inventive concepts 172to 174, wherein the molecular component comprises ethane.

Inventive concept 177. The system any one of Inventive concepts 172 to174, wherein the molecular component comprises propane.

Inventive concept 178. The system of any one of Inventive concepts 172to 174, wherein the molecular component comprises butane.

Inventive concept 179. The system of any one of Inventive concepts 172to 174, wherein the molecular component comprises pentane.

Inventive concept 180. The system of Inventive concept 172, wherein (i)the isotopic signature is based upon an isotope ratio, and the isotopicratio is of the form δ(C_(X)H_(Y-1)D/C_(A)H_(B)), (ii) C_(X)H_(Y-1)D isa monodeuterated molecule of a first hydrocarbon selected from ahydrocarbon group consisting of: methane, ethane, propane, butane andpentane hydrocarbon, and (iii) C_(A)H_(B) is a non-deuterated moleculeof a second hydrocarbon that is not the first hydrocarbon, selected fromthe hydrocarbon group.

Inventive concept 181. The system of Inventive concept 172, wherein (i)the isotopic signature has the form δ(EXP₁/EXP₂), (ii) EXP₁ is anexpression representing a monodeuterated multi-alkane sum of respectiveconcentrations of one or more of: monodeuterated ethane, monodeuteratedpropane, monodeuterated butane, and monodeuterated pentane, and (iii)EXP₂ is an expression representing a concentration of monodeuteratedmethane.

Inventive concept 182. The system of Inventive concept 172, wherein (i)the isotopic signature has the form δ(EXP₁/EXP₂), (ii) EXP₁ is anexpression representing a monodeuterated-methane concentration, and(iii) EXP₂ is an expression representing a respective concentration ofany one of: monodeuterated ethane, monodeuterated propane,monodeuterated butane, and monodeuterated pentane.

Inventive concept 183. The system of Inventive concept 172, wherein (i)the isotopic signature has the form δ(EXP₁/EXP₂), (ii) EXP₁ is anexpression representing respective concentrations of one or more membersof the monodeuterated C1-C5 alkane group consisting of monodeuteratedmethane, monodeuterated ethane, monodeuterated propane, monodeuteratedbutane, and monodeuterated pentane, and (iii) EXP₂ is an expressionrepresenting respective concentrations of one or more members of saidmonodeuterated C1-C5 alkane group with the exception of the one or moremembers represented in EXP₁. wherein (i) the isotopic signature has theform δ(EXP₁/EXP₂), (ii) EXP₁ is an expression representing any member ofthe monodeuterated C1-C5 alkane group consisting of monodeuteratedmethane, monodeuterated ethane, monodeuterated propane, monodeuteratedbutane, and monodeuterated pentane, and EXP₂ is an expressionrepresenting any other member of said monodeuterated C1-C5 alkane group.

Inventive concept 185. The system of Inventive concept 172, wherein theisotopic signature is based upon a ratio of isotope ratios and has theform δ(¹³C)_(ALKANE1)/δ(¹³C)_(ALKANE2), where each of ALKANE1 andALKANE2 includes an alkane selected from an alkane group consisting of:methane, ethane, propane, butane and pentane.

Inventive concept 186. The system of Inventive concept 185, wherein atleast one of ALKANE1 and ALKANE2 includes an arithmetic combination ofmultiple alkanes selected from the alkane group.

Inventive concept 187. The system of any one of Inventive concepts 172to 186, wherein the pumping arrangements are operative to inject thehydrogen-containing gas at a pressure that is at least 500 PSI higherthan the current shut-in gas pressure at the wellbore.

Inventive concept 188. The system of any one of Inventive concepts 172to 187, additionally including surface geophysical-monitoring equipmentfor determining whether hydraulic fractures are being extended by thehydrogen injection.

Inventive concept 189. The system of any one of Inventive concepts 172to 188, additionally including a tracer-gas facility for adding agas-phase tracer to the injected hydrogen gas.

Inventive concept 190. The system of any one of Inventive concepts 172to 189, wherein the recovered portion of the hydrogen gas has an H₂molar fraction of at least 90%.

Inventive concept 191. The system of any one of Inventive concepts 172to 190, wherein the recovered portion of the hydrogen gas has an H₂molar fraction of at least 95%.

Inventive concept 192. The system of any one of Inventive concepts 172to 191, wherein the recovered portion of the hydrogen gas has an H₂molar fraction of at least 97%.

Inventive concept 193. The system of any one of Inventive concepts 172to 192, wherein a kerogen concentration in the reservoir is at least 2%by volume.

Inventive concept 194. A method of storing and recovering hydrogen gasin a kerogen-rich unconventional gas reservoir, the method comprising:a. injecting a fracturing fluid through a horizontal wellbore into thegas reservoir to cause fracturing within the gas reservoir; b.recovering a methane-containing gas through the wellbore; c. projectinga reservoir isotope ratio value I-RATIO_(RES)(T_(RES)) respective of oneor more molecular components of a methane-containing gas recovered fromthe gas reservoir at each of a plurality of corresponding reservoirpressures PRESSURE_(RES)(T_(RES)) at respective reservoir times T_(RES),wherein the projecting includes: i. sampling a gas mixture recoveredfrom a gas-reservoir core sample to determine a plurality of core-samplevalue-pairs for respective core-sample times T_(CS), each core-samplevalue-pair including a core-sample isotope ratio I-RATIO_(CS)(T_(CS))value and a respective core-sample pressure value PRESSURE_(CS)(T_(CS)),and ii. matching PRESSURE_(RES)(T_(RES)) values with respectivePRESSURE_(CS)(T_(CS)) values of the plurality of core-sample value-pairsto project I-RATIO_(RES)(T_(RES)) values based on respectiveI-RATIO_(CS)(T_(CS)) values corresponding to the matched respectivePRESSURE_(CS)(T_(CS)) values; d. responsively to and contingent uponreaching an isotopic-signature trigger criterion based upon saidprojecting of reservoir isotope ratio values I-RATIO_(RES)(T_(RES)),injecting hydrogen gas through the wellbore into the geologicalformation at a shut-in gas pressure at a wellhead; and e. recovering,through the wellbore, a hydrogen-containing gas having an H₂ molarfraction of at least 85%.

Inventive concept 195. The method of Inventive concept 194, wherein thesampling of the recovered gas mixture includes: i. receiving, in acore-sample holder, a core sample obtained from the gas reservoir, ii.introducing, into the core-sample holder, a methane-containing gas forwhich an isotope ratio I-RATIO is known, the introducing includingregulating an internal gas pressure of the core-sample holder to aninitial core-sample pressure PRESSURE_(CS-INIT), iii. periodicallysampling a gas mixture comprising a methane-containing gas produced bythe core sample in the core-sample holder at a core-sample pressurePRESSURE_(CS)(T_(CS)), and iv. determining a core-sample isotope ratioI-RATIO_(CS)(T_(CS)) of the sampled gas mixture, for each of a pluralityof periodic samplings at respective values of PRESSURE_(CS)(T_(CS)).

Inventive concept 196. The method of either one of Inventive concepts194 or 195, wherein the reaching the isotopic-signature triggercriterion includes detecting a decrease in the projected reservoirisotope ratio I-RATIO_(RES)(T_(RES)) from an initial value to a minimumvalue and, subsequently thereto, detecting an increase in the projectedreservoir isotope ratio I-RATIO_(RES)(T_(RES)).

Inventive concept 197. The method of Inventive concept 196, whereinreaching the isotopic-signature trigger criterion includes detecting anincrease in the projected reservoir isotope ratio I-RATIO_(RES)(T_(RES))respective of at least two successive samplings of the recoveredmethane-containing gas.

Inventive concept 198. The method of any one of Inventive concepts 194to 197, wherein (i) PRESSURE_(CS-INIT) equals PRESSURE_(RES-INIT), and(ii) the projecting includes projecting a I-RATIO_(RES)(T_(RES)) valueas being equal to a I-RATIO_(CS)(T_(CS)) value of a given core-samplevalue pair, for a corresponding reservoir pressurePRESSURE_(RES)(T_(RES)) equal to a PRESSURE_(CS)(T_(CS)) value of thesame given core-sample value pair.

Inventive concept 199. The method of any one of Inventive concepts 194to 198, wherein (i) PRESSURE_(CS-INIT) is not equal toPRESSURE_(RES-INIT), and (ii) the projecting includes adjusting aprojected value of I-RATIO_(RES)(T_(RES)) for a difference betweenPRESSURE_(CS-INIT) and PRESSURE_(RES-INIT).

Inventive concept 200. The method of any one of Inventive concepts 194to 199, wherein the isotope ratio I-RATIO has the form δ(¹³C).

Inventive concept 201. The method of any one of Inventive concepts anyone of Inventive concepts 194 to 199, wherein the isotope ratio I-RATIOhas the form δ(C_(X)H_(Y-1)D/C_(X)H_(Y)).

Inventive concept 202. The method of any one of Inventive concepts anyone of Inventive concepts 194 to 201, wherein the one or more molecularcomponents comprises methane, and the isotope ratio I-RATIO isδ(CH₃D/CH₄).

Inventive concept 203. The method of any one of Inventive concepts 194to 201, wherein the one or more molecular components comprises ethane,and the isotope ratio I-RATIO is δ(C₂H₅D/C₂H₆).

Inventive concept 204. The method of any one of Inventive concepts 194to 201, wherein the one or more molecular components comprises propane,and the isotope ratio I-RATIO is δ(C₃H₇D/C₃H₈).

Inventive concept 205. The method of any one of Inventive concepts 194to 201, wherein the one or more molecular components comprises butane,and the isotope ratio I-RATIO is δ(C₄H₉D/C₄H₁₀).

Inventive concept 206. The method of any one of Inventive concepts 194to 201, wherein the one or more molecular components comprises pentane,and the isotope ratio I-RATIO is δ(C₅H₁₁D/C₅H₁₂).

Inventive concept 207. The method of any one of Inventive concepts anyone of Inventive concepts 194 to 199, wherein (i) the isotope ratioI-RATIO has the form δ(C_(X)H_(Y-1)D/C_(A)H_(B)), (ii) C_(X)H_(Y-1)D isa monodeuterated molecule of a first hydrocarbon selected from ahydrocarbon group consisting of: methane, ethane, propane, butane, andpentane hydrocarbon, and (iii) C_(A)H_(B) is a non-deuterated moleculeof a second hydrocarbon that is not the first hydrocarbon, selected fromthe hydrocarbon group.

Inventive concept 208. The method of any one of Inventive concepts 194to 199, wherein (i) the isotope ratio I-RATIO has the form δ(EXP₁/EXP₂),(ii) EXP₁ is an expression representing a monodeuterated multi-alkanesum of respective concentrations of one or more of: monodeuteratedethane, monodeuterated propane, monodeuterated butane, andmonodeuterated pentane, and (iii) EXP₂ is an expression representing aconcentration of monodeuterated methane.

Inventive concept 209. The method of any one of Inventive concepts 194to 199, wherein (i) the isotope ratio I-RATIO has the form δ(EXP₁/EXP₂),(ii) EXP₁ is an expression representing a monodeuterated-methaneconcentration, and (iii) EXP₂ is an expression representing a respectiveconcentration of any one of: monodeuterated ethane, monodeuteratedpropane, monodeuterated butane, and monodeuterated pentane.

Inventive concept 210. The method of any one of Inventive concepts 194to 199, wherein (i) the isotope ratio I-RATIO has the form δ(EXP₁/EXP₂),(ii) EXP₁ is an expression representing respective concentrations of oneor more members of the monodeuterated C1-C5 alkane group consisting ofmonodeuterated methane, monodeuterated ethane, monodeuterated propane,monodeuterated butane, and monodeuterated pentane, and (iii) EXP₂ is anexpression representing respective concentrations of one or more membersof said monodeuterated C1-C5 alkane group with the exception of the oneor more members represented in EXP₁.

Inventive concept 211. The method of any one of Inventive concepts 194to 199, wherein (i) the isotope ratio I-RATIO has the form δ(EXP₁/EXP₂),(ii) EXP₁ is an expression representing any member of the monodeuteratedC1-C5 alkane group consisting of monodeuterated methane, monodeuteratedethane, monodeuterated propane, monodeuterated butane, andmonodeuterated pentane, and (iii) EXP₂ is an expression representing anyother member of said monodeuterated C1-C5 alkane group.

Inventive concept 212. The method of any one of Inventive concepts 194to 199, wherein the isotope ratio I-RATIO is based upon a ratio ofisotope ratios and has the form δ(¹³C)_(ALKANE1)/δ(¹³C)_(ALKANE2), whereeach of ALKANE1 and ALKANE2 includes an alkane selected from an alkanegroup consisting of: methane, ethane, propane, butane and pentane.

Inventive concept 213. The method of any one of Inventive concepts 194to 212, wherein for any two successive samplings, the time betweenT_(RES) values respective of PRESSURE_(RES)(T_(RES)) values matching thePRESSURE_(CS)(T_(CS)) values of the two successive samples is at least50 times longer than the time between the corresponding T_(CS) values ofthe two successive samples.

Inventive concept 214. The method of any one of Inventive concepts 194to 213, wherein the recovered hydrogen-containing gas has an H₂ molarfraction of at least 90%.

Inventive concept 215. The method of any one of Inventive concepts 194to 214, wherein the recovered hydrogen-containing gas has an H₂ molarfraction of at least 95%.

Inventive concept 216. The method of any one of Inventive concepts 194to 215, wherein the recovered hydrogen-containing gas has an H₂ molarfraction of at least 97%.

Inventive concept 217. The method of any one of Inventive concepts 194to 216, wherein the kerogen concentration of the kerogen-rich geologicalformation is at least 2% by volume.

Inventive concept 218. A method of storing and recovering hydrogen gasin a kerogen-rich unconventional gas reservoir, the method comprising:a. injecting a fracturing fluid through a horizontal wellbore into thegas reservoir to cause fracturing within the gas reservoir; b.recovering a methane-containing gas through the wellbore; c. projectingan H₂ molar fraction χ(H₂)_(RES)(T_(RES)) of a hydrogen-containing gasrecovered from the gas reservoir at each of a plurality of correspondingreservoir pressures PRESSURE_(RES)(T_(RES)) at respective reservoirtimes T_(RES), the projecting including: i. sampling ahydrogen-containing gas recovered from a gas-reservoir core sample heldin the core-sample holder, to determine a plurality of core-samplevalue-pairs for respective core-sample times T_(CS), each core-samplevalue-pair including an H₂ molar fraction value χ(H₂)_(CS)(T_(CS)) and arespective core-sample pressure value PRESSURE_(CS)(T_(CS)), and ii.matching PRESSURE_(RES)(T_(RES)) values with respectivePRESSURE_(CS)(T_(CS)) values of the plurality of core-sample value-pairsto project χ(H₂)_(RES)(T_(RES)) values based on respectiveχ(H₂)_(CS)(T_(CS)) values corresponding to the matched respectivePRESSURE_(CS)(T_(CS)) values; d. responsively to and contingent uponreaching a hydrogen-purity trigger criterion based upon said projectingof H₂ molar fraction values χ(H₂)_(RES)(T_(RES)), injecting hydrogen gasthrough the wellbore into the gas reservoir at a shut-in gas pressure ata wellhead; and e. recovering, through the wellbore, ahydrogen-containing gas having an H₂ molar fraction equal to or greaterthan the hydrogen-purity trigger criterion.

Inventive concept 219. The method of Inventive concept 218, wherein thesampling includes introducing a hydrogen-containing gas for which an H₂molar fraction χ(H₂) is known into the core-sample holder at a pressurehigher than an equilibrium gas pressure therein.

Inventive concept 220. The method of Inventive concept 219, wherein eachperiodic sampling is of a respective hydrogen-containing gas recoveredfrom a same gas-reservoir core sample.

Inventive concept 221. The method of Inventive concept 219, wherein atleast two periodic samplings are of a respective hydrogen-containing gasrecovered from different gas-reservoir core samples.

Inventive concept 222. The method of any one of Inventive concepts 218to 221, wherein the hydrogen-purity trigger criterion is that thehydrogen-containing gas has an H₂ molar fraction of at least 85%.

Inventive concept 223. The method of any one of Inventive concepts 218to 222, wherein the hydrogen-purity trigger criterion is that thehydrogen-containing gas has an H₂ molar fraction of at least 90%.

Inventive concept 224. The method of any one of Inventive concepts 218to 223, wherein the hydrogen-purity trigger criterion is that thehydrogen-containing gas has an H₂ molar fraction of at least 95%.

Inventive concept 225. The method of any one of Inventive concepts 218to 224, wherein the hydrogen-purity trigger criterion is that thehydrogen-containing gas has an H₂ molar fraction of at least 97%.

Inventive concept 226. The method of any one of Inventive concepts 218to 225, wherein the kerogen concentration of the kerogen-rich geologicalformation is at least 2% by volume.

Inventive concept 227. The method of any one of Inventive concepts 218to 226, wherein the known H₂ molar fraction of the hydrogen-containinggas introduced into the core-sample holder is greater than or equal tothe H₂ molar fraction respective of the hydrogen-purity triggercriterion.

Inventive concept 228. The method of any one of Inventive concepts 218to 227, wherein for any two successive periodic samplings, the timebetween T_(RES) values respective of PRESSURE_(RES)(T_(RES)) valuesmatching the PRESSURE_(CS)(T_(CS)) values of the two successive samplesis at least 50 times longer than the time between the correspondingT_(CS) values of the two successive samples.

Inventive concept 229. A method of projecting an isotope ratioI-RATIO_(RES) respective of one or more molecular components in amethane-containing gas recovered from a kerogen-rich unconventional gasreservoir, the method comprising: a. receiving, in a core-sample holder,a core sample acquired from the gas reservoir; b. introducing, into thecore-sample holder, a methane-containing gas for which an isotope ratioI-RATIO is known, the introducing including regulating an internal gaspressure of the core-sample holder to an initial core-sample pressurePRESSURE_(CS-INIT); c. sampling, periodically, a gas mixture comprisinga methane-containing gas produced by a core sample held in thecore-sample holder at a core-sample pressure PRESSURE_(CS)(T_(CS)) atrespective core-sample times T_(CS); d. determining a core-sampleisotope ratio I-RATIO_(CS)(T_(CS)) of the sampled gas mixture for eachof a plurality of samplings; and e. projecting a reservoir isotope ratioI-RATIO_(RES)(T_(RES)) value for a methane-containing gas recovered fromthe gas reservoir at a corresponding reservoir pressurePRESSURE_(RES)(T_(RES)) at respective reservoir times T_(RES), by usinga recorded plurality of core-sample value pairs each including aI-RATIO_(CS)(T_(CS)) value and a corresponding PRESSURE_(CS)(T_(CS))value.

Inventive concept 230. The method of Inventive concept 229, wherein (i)PRESSURE_(CS-INIT) equals PRESSURE_(RES-INIT), and (ii) the projectingincludes projecting a I-RATIO_(RES)(T_(RES)) value as being equal to aI-RATIO_(CS)(T_(CS)) value of a given core-sample value pair, for acorresponding reservoir pressure PRESSURE_(RES)(T_(RES)) equal to aPRESSURE_(CS)(T_(CS)) value of the same given core-sample value pair.

Inventive concept 231. The method of Inventive concept 229, wherein (i)PRESSURE_(CS-INIT) is not equal to PRESSURE_(RES-INIT), and (ii) theprojecting includes adjusting a projected value ofI-RATIO_(RES)(T_(RES)) for a difference between PRESSURE_(CS-INIT) andPRESSURE_(RES-INIT).

Inventive concept 232. The method of any one of Inventive concepts 229to 231, wherein the isotope ratio I-RATIO has the form δ(¹³C).

Inventive concept 233. The method of any one of Inventive concepts 229to 231, wherein the isotope ratio I-RATIO has the formδ(C_(X)H_(Y-1)D/C_(X)H_(Y)).

Inventive concept 234. The method of any one of Inventive concepts 229to 233, wherein the one or more molecular components comprises methane,and the isotope ratio I-RATIO is δ(CH₃D/CH₄).

Inventive concept 235. The method of any one of Inventive concepts 229to 233, wherein the one or more molecular components comprises ethane,and the isotope ratio I-RATIO is δ(C₂H₅D/C₂H₆).

Inventive concept 236. The method of any one of Inventive concepts 229to 233, wherein the one or more molecular components comprises propane,and the isotope ratio I-RATIO is δ(C₃H₇D/C₃H₈).

Inventive concept 237. The method of any one of Inventive concepts 229to 233, wherein the one or more molecular components comprises butane,and the isotope ratio I-RATIO is δ(C₄H₉D/C₄H₁₀).

Inventive concept 238. The method of any one of Inventive concepts 229to 233, wherein the one or more molecular components comprises pentane,and the isotope ratio I-RATIO is δ(C₅H₁₁D/C₅H₁₂).

Inventive concept 239. The method of any one of Inventive concepts 229to 231, wherein (i) the isotope ratio I-RATIO has the formδ(C_(X)H_(Y-1)D/C_(A)H_(B)), (ii) C_(X)H_(Y-1)D is a monodeuteratedmolecule of a first hydrocarbon selected from a hydrocarbon groupconsisting of: methane, ethane, propane, butane and pentane hydrocarbon,and (iii) C_(A)H_(B) is a non-deuterated molecule of a secondhydrocarbon that is not the first hydrocarbon, selected from thehydrocarbon group.

Inventive concept 240. The method of any one of Inventive concepts 229to 231, wherein (i) the isotope ratio I-RATIO has the form δ(EXP₁/EXP₂),(ii) EXP₁ is an expression representing a monodeuterated multi-alkanesum of respective concentrations of one or more of: monodeuteratedethane, monodeuterated propane, monodeuterated butane, andmonodeuterated pentane, and (iii) EXP₂ is an expression representing aconcentration of monodeuterated methane.

Inventive concept 241. The method of any one of Inventive concepts 229to 231, wherein (i) the isotope ratio I-RATIO has the form δ(EXP₁/EXP₂),(ii) EXP₁ is an expression representing a monodeuterated-methaneconcentration, and (iii) EXP₂ is an expression representing a respectiveconcentration of any one of: monodeuterated ethane, monodeuteratedpropane, monodeuterated butane, and monodeuterated pentane.

Inventive concept 242. The method of any one of Inventive concepts 229to 231, wherein (i) the isotope ratio I-RATIO has the form δ(EXP₁/EXP₂),(ii) EXP₁ is an expression representing respective concentrations of oneor more members of the monodeuterated C1-C5 alkane group consisting ofmonodeuterated methane, monodeuterated ethane, monodeuterated propane,monodeuterated butane, and monodeuterated pentane, and (iii) EXP₂ is anexpression representing respective concentrations of one or more membersof said monodeuterated C1-C5 alkane group with the exception of the oneor more members represented in EXP₁.

Inventive concept 243. The method of any one of Inventive concepts 229to 231, wherein (i) the isotope ratio I-RATIO has the form δ(EXP₁/EXP₂),(ii) EXP₁ is an expression representing any member of the monodeuteratedC1-C5 alkane group consisting of monodeuterated methane, monodeuteratedethane, monodeuterated propane, monodeuterated butane, andmonodeuterated pentane, and (iii) EXP₂ is an expression representing anyother member of said monodeuterated C1-C5 alkane group.

Inventive concept 244. The method of any one of Inventive concepts 229to 231, wherein the isotope ratio I-RATIO is based upon a ratio ofisotope ratios and has the form δ(¹³C)_(ALKANE1)/δ(¹³C)_(ALKANE2), whereeach of ALKANE1 and ALKANE2 includes an alkane selected from an alkanegroup consisting of: methane, ethane, propane, butane, and pentane.

Inventive concept 245. A method of projecting an H₂ molar fractionχ(H2)_(RES) of a hydrogen-containing gas recovered from storage in akerogen-rich unconventional gas reservoir, the method comprising: a.receiving, in a core-sample holder, a core sample acquired from the gasreservoir; b. sampling, periodically, a gas mixture comprising ahydrogen-containing gas produced by the core sample in the core-sampleholder at a core-sample pressure PRESSURE_(CS)(T_(CS)); c. determining acore-sample H₂ molar fraction χ(H₂)_(CS)(T_(CS)) of the sampled gasmixture for each of a plurality of samplings; and d. projecting areservoir isotope ratio χ(H₂)_(RES)(T_(RES)) value for ahydrogen-containing gas recovered from the reservoir at a correspondingreservoir pressure PRESSURE_(RES)(T_(RES)), by using a recordedplurality of core-sample value pairs each including a χ(H₂)_(CS)(T_(CS))value and a corresponding PRESSURE_(CS)(T_(CS)) value.

Inventive concept 246. The method of Inventive concept 245, wherein thesampling includes introducing, into the core-sample holder, ahydrogen-containing gas for which an H₂ molar fraction χ(H₂) is known,the introducing including regulating an internal gas pressure of thecore-sample holder to an initial core-sample pressurePRESSURE_(CS-INIT).

Inventive concept 247. The method of Inventive concept 246, wherein eachperiodic sampling is of a respective hydrogen-containing gas recoveredfrom a same gas-reservoir core sample.

Inventive concept 248. The method of Inventive concept 247, wherein atleast two periodic samplings are of a respective hydrogen-containing gasrecovered from different gas-reservoir core samples.

Inventive concept 249. Apparatus comprising: a. a core-sample holder forreceiving a core sample acquired from a kerogen-rich unconventional gasreservoir; b. pressure-regulating arrangements arranged to be placed influid communication with the core-sample holder and to evacuate thecore-sample holder; c. at least one of: i. a pressurized volume of amethane-containing gas for which an isotope ratio I-RATIO respective ofone or more molecular components of the methane-containing gas is known,arranged to be placed in fluid communication with the evacuatedcore-sample holder and effective to achieve a gas pressure therein equalto the initial reservoir pressure PRESSURE_(RES-INIT), and ii. apressurized volume of a hydrogen-containing gas for which an H₂ molarfraction χ(H₂) is known, arranged to be placed in fluid communicationwith the evacuated core-sample holder and effective to achieve a gaspressure therein equal to the initial reservoir pressurePRESSURE_(R-INIT); d. a pressure-control valve configured to allowpassage therethrough of a gas mixture which comprises amethane-containing gas produced by the core sample, at a core-samplepressure PRESSURE_(CS)(T_(CS)) at respective core-sample times T_(CS);e. one or more gas-sampling containers arranged to receive the gasmixture passed through the pressure-control valve; and f.instrumentation for measuring the core-sample pressurePRESSURE_(CS)(T_(CS)) and a core-sample isotope ratioI-RATIO_(CS)(T_(CS)) of the gas mixture at respective core-sample timesT_(CS).

Inventive concept 250. The apparatus of Inventive concept 249, whereinthe isotope ratio I-RATIO has the form δ(¹³C).

Inventive concept 251. The apparatus of Inventive concept 249, whereinthe isotope ratio I-RATIO has the form δ(C_(X)H_(Y-1)D/C_(X)H_(Y)).

Inventive concept 252. The apparatus of any one of Inventive concepts249 to 251, wherein the one or more molecular components comprisesmethane, and the isotope ratio I-RATIO is δ(CH₃D/CH₄).

Inventive concept 253. The apparatus of any one of Inventive concepts249 to 251, wherein the one or more molecular components comprisesethane, and the isotope ratio I-RATIO is δ(C₂H₅D/C₂H₆).

Inventive concept 254. The apparatus of any one of Inventive concepts249 to 251, wherein the one or more molecular components comprisespropane, and the isotope ratio I-RATIO is δ(C₃H₇D/C₃H₈).

Inventive concept 255. The apparatus of any one of Inventive concepts249 to 251, wherein the one or more molecular components comprisesbutane, and the isotope ratio I-RATIO is δ(C₄H₉D/C₄H₁₀).

Inventive concept 256. The apparatus of any one of Inventive concepts249 to 251, wherein the one or more molecular components comprisespentane, and the isotope ratio I-RATIO is δ(C₅H₁₁D/C₅H₁₂).

Inventive concept 257. The apparatus of Inventive concept 249, wherein(i) the isotope ratio I-RATIO has the form δ(C_(X)H_(Y-1)D/C_(A)H_(B)),(ii) C_(X)H_(Y-1)D is a monodeuterated molecule of a first hydrocarbonselected from a hydrocarbon group consisting of: methane, ethane,propane, butane, and pentane hydrocarbon, and (iii) C_(A)H_(B) is anon-deuterated molecule of a second hydrocarbon that is not the firsthydrocarbon, selected from the hydrocarbon group.

Inventive concept 258. The apparatus of Inventive concept 249, wherein(i) the isotope ratio I-RATIO has the form δ(EXP₁/EXP₂), (ii) EXP₁ is anexpression representing a monodeuterated multi-alkane sum of respectiveconcentrations of one or more of: monodeuterated ethane, monodeuteratedpropane, monodeuterated butane, and monodeuterated pentane, and (iii)EXP₂ is an expression representing a concentration of monodeuteratedmethane.

Inventive concept 259. The apparatus of Inventive concept 249, wherein(i) the isotope ratio I-RATIO has the form δ(EXP₁/EXP₂), (ii) EXP₁ is anexpression representing a monodeuterated-methane concentration, and(iii) EXP₂ is an expression representing a respective concentration ofany one of: monodeuterated ethane, monodeuterated propane,monodeuterated butane, and monodeuterated pentane.

Inventive concept 260. The apparatus of Inventive Concept 249, wherein(i) the isotope ratio I-RATIO has the form δ(EXP₁/EXP₂), (ii) EXP₁ is anexpression representing respective concentrations of one or more membersof the monodeuterated C1-C5 alkane group consisting of monodeuteratedmethane, monodeuterated ethane, monodeuterated propane, monodeuteratedbutane, and monodeuterated pentane, and (iii) EXP₂ is an expressionrepresenting respective concentrations of one or more members of saidmonodeuterated C1-C5 alkane group with the exception of the one or moremembers represented in EXP₁.

Inventive concept 261. The apparatus of Inventive concept 249, wherein(i) the isotope ratio I-RATIO has the form δ(EXP₁/EXP₂), (ii) EXP₁ is anexpression representing any member of the monodeuterated C1-C5 alkanegroup consisting of monodeuterated methane, monodeuterated ethane,monodeuterated propane, monodeuterated butane, and monodeuteratedpentane, and (iii) EXP₂ is an expression representing any other memberof said monodeuterated C1-C5 alkane group.

Inventive concept 262. The apparatus of Inventive concept 249, whereinthe isotope ratio I-RATIO is based upon a ratio of isotope ratios andhas the form δ(¹³C)_(ALKANE1)/δ(¹³C)_(ALKANE2), where each of ALKANE1and ALKANE2 includes an alkane selected from an alkane group consistingof: methane, ethane, propane, butane and pentane.

The present invention has been described using detailed descriptions ofembodiments thereof that are provided by way of example and are notintended to limit the scope of the invention. The described embodimentscomprise different features, not all of which are required in allembodiments of the invention. Some embodiments of the present inventionutilize only some of the features or possible combinations of thefeatures. Variations of embodiments of the present invention that aredescribed and embodiments of the present invention comprising differentcombinations of features noted in the described embodiments will occurto persons skilled in the art to which the invention pertains.

1. A method of operating a kerogen-rich unconventional gas reservoircharacterized by there being multiple hydraulically-fractured wellsdrilled thereinto, the method comprising: a. recovering amethane-containing gas from a first hydraulically-fractured well drilledinto the gas reservoir; b. steam-methane reforming the recoveredmethane-containing gas to yield a hydrogen gas and an inorganiccarbon-containing gas; c. injecting at least a portion of the hydrogengas into a second hydraulically-fractured well drilled into the gasreservoir; and d. injecting at least a portion of the inorganiccarbon-containing gas into a third hydraulically-fractured well drilledinto the gas reservoir. 2-262. (canceled)